Drilling Fluids

Zheng Xiuhua, Ma Xiaochun

Drilling Fluids (第一版)

2010

地质出版社

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内容提要 本书参考国内外钻/完井液专著、石油/泥浆服务技术手册、科技论文等编写而成，系统 介绍了钻井液的基本原理、钻井液材料和钻井液体系，同时介绍了钻/完井液技术的最新进 展。全书分为十章，主要内容包括钻井液概述、钻井液性能及其测试、粘土矿物及胶体化学、 钻井液流变和水力性能，钻井液滤失性能、钻井液材料和处理剂、水基钻井液体系、孔壁稳 定与漏失、固相控制、钻井液技术新进展。本书为开设钻井液，特别是采用双语教学的大专 院校提供了一本很好的英文教材。 Abstract This book was accomplished referred many literatures on drilling/completion fluids, such as monographs, technique manuals from petroleum/mud service companies and published articles, both domestic and abroad. This book introduced systematically the principles of drilling fluids, make-up materials, additives and drilling fluids systems. This book is divided into ten chapters, i.e., the INTRODUCTION TO DRILLING FLUIDS, THE PROPERTIES AND EVALUATI ON OF DRILLING FLUIDS, CALY MINERALOGY AND THE COLLOD CHEMISTRY OF DRILLING FLUID, RHEOLOGY AND HYDRAULICS, MAKE-UP MATERIALS AND ADITIVES, WATER-BASE DRILLING FLUID SYSTEM, HOLE STABILT Y AND LOSS CIRCULATION, SOLID CONTROL, and SOME UP TO DATE TECHNOLOGIES FOR DRILLING FLUID. This book tries to provide the students, especially in bilingual language a teaching book.

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前言 随着油气勘探开发井和矿产资源勘探孔变得原来越深和越来越复杂，基础工程勘察领域 越来越广，要求钻井液分多样，性能可调，以满足各种钻井情况。 As attempts are made to drill deeper and consequently more hazardous wells to exploit petroleum and mineral resources, the drilling fluid is expected to have physical and chemical properties that enable it to contend with a greater variety of well conditions. The satisfactory performance of these more complex functions has required that the composition of the fluid become more varied and its properties more subject to control. 最初钻井液的功能只是携带岩屑，现在已经公认钻井液是钻井成功的主要因素之一，同 时也与钻进效率和钻进成本有直接关系。因此，钻井液组分、性能和功用及其设计与维护至 关重要。 The fluid used in rotary drilling, once regarded only as a means of bringing rock cuttings to the surface, is now recognized as one of the major factors involved in the success or failure of the drilling operation. In addition to lifting the cuttings, the drilling fluid must perform other, equally important functions directed toward the efficiency and cost. For this reason, the composition of the drilling fluid and its resulting properties and their design and maintenance are significant. 勘查与技术工程的学生就业涵盖了石油工程、矿产勘查、资源勘探、工程勘察等工程领 域，钻井液是该专业的主修课程之一。 随着我国工程在国际市场上占有份额的增加，有的 毕业生被派往国外做技术负责；同时，有一部分学生深造攻读硕士和博士学位，有很多参与 国际交流的机会；另外，有许多国外大学提出了联合培养合作意向；还有，我国高等教育部 为提高学生素质、培养国际意识和交流能力，在外语教学投入了很多力量，学生也投入了大 量精力。以上这些因素要求，在有条件的情况下开设双语教学，使学生培养使用英语的习惯， 学以致用，认识英语只是一种交流工具。 The employment of students majored Prospection and Engineering nowadays covers many engineering fields, e.g. petroleum engineering, mineral survey, resource exploration and project investigation, etc., for which drilling fluid is one of the main subjects they major. And the following factors, i.e. 1) some are sent abroad as engineers as the international project growth; 2)some purse master and doctor degrees, for which they have more opportunities to international programs; 3)some universities proposed cooperation for high education; 4) the students have already learned English for many years under many supports of the Education Ministry, demonstrate that it is significant and possible to have some curricula in bilingual under some conditions, to help students to know that English is just a communication tool. 本书为开设钻井液双语教学提供教材。以英语形式书写，专业词汇在括号中用英语标注。 钻井液双语教学理念是利用英语学习专业知识，通过教学首先要掌握钻井液专业知识和专业 技能，同时了解专业知识的英文表达。专业知识为教学根本，英语只是一种语言，在某种程 度上更严谨地阐述科学原理。 This book tries to provide a teaching book of drilling fluids which is lectured in bilingual language. It is written in English, and the speciality words are translated to Chines in bracket. The teaching aim is firstly to convey speciality knowledge and skills, along with their expression in English. 考虑有些学生阅读英文专业文献较少，开始学习时会有困难。在学习中将采取以下几点 措施确保教学质量和效果。第一点也是最重要的一点是： “万事开头难”，要求学生有信心而 且能够坚持。第二点是配置与英文教材内容基本一致的中文教材，同时开设实验课，采用中

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文实验指导书。第三点将采取循序渐进的教学方法，开始时专业术语将分别以英文和中文同 时讲授。 Considering that some students may read few English specialty literatures, it will be a bit difficult to start. Some measures shall be taken to assure the teaching quality and results. The first and the most important one is for students, i.e. Be Confident and Persevere. Nothing is easy to start. The second one is to facilitate it with Chinese specialty literature, in which the contents are consistent with the teaching contents in English, along with experiments in Chinese. The third one is to go ahead it gradually, namely the terms will be presented at the beginning both in English and Chinese. 本书由郑秀华主编，马孝春统稿。内容由中国地质大学（北京）工程技术学院勘查教研 室讨论制定，由《钻井液工艺原理》双语教学团队共同编写。 The book is edited by Prof. Dr. Xiuhua Zheng and collated by Prof. Dr. Xiaochun Ma. The contents of this book is organized by the Prospection and Technology Institute, School of Engineering and Technology, China University of Geosceicens(Beijing), co-edited by the teaching group for drilling fluids.

致 谢 本书出版得到了中国地质大学（北京），工程技术学院和教研室与相关领部门及其领导 的鼓励和支持。 本书的编写过程中得到了很多人的帮助，包括德国柏林工业大学 Helmut Wolff 教授，他 最早向作者提供了钻井液原本教材。中国石油勘探开发研究院的樊世忠教授，他为作者提供 了许多他珍藏多年的文献资料，包括一些外国公司的泥浆技术手册。中国石油大学的鄢捷年 教授，在本书的编写过程中，作者参考了鄢捷年教授的教材。感谢研究生们，他们是王彬、 程金霞、尹文斌、李纯、詹美萍、陈立敏、刘选朋、刘翠娜、张志亮等，他们为本书的编写 作了许多繁琐而细微的工作。还有许多未能详尽提及的人，他们为本书做出了很大贡献。在 此一并表示感谢！

Acknowledgement The authors appreciate CUGB, School and Institute for their encouragement and support. The authors acknowledge Prof. Dr. Helmut Wolf of Technolgy University of Berlin, Germany who provided many literatures for drilling fluids in English, Prof. Shizhong Fan who dedicated his collection for drilling fluids in English, and Prof. Jienian Yan whose teaching book has been referred. The authors thank many undergraduated students, i.e. Bin Wang, Jinxia Cheng, Wenbin Yin, Chun Li, Meiping Zhan, Limin Chen, Xuanpeng Liu, Cuina Liu, Zhiliang Zhang, etc., along with many unnamed above. The Author would like to express her many thank to his son and his husband, especially his son, who is now in his 2nd year of high school. He supported his mother with his effort for his school work.

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About the Authors Xiuhua Zheng holds B.S and M.S. in Exploration Engineering from Changchun Geology College, which is now the Geosciences Center of Jilin University and a Ph.D. degree in Geotechnique from China University of Geosciences(Beijing). She finished her thesis on foaming agents and applications for well drilling, and her dissertation was about underbalanced drilling and its optimization. She worked on fracturing fluids and drilling fluids for coal bed methane at Exploration Engineering Institute from 1990 to 1993. She has engaged herself in teaching and researching in the fields of drilling and completion fluids, geothermal energy since she came to university in 1993. She has published more than 40 papers, edited or co-edited 4 books published publicly and 1 teaching books used at university, and holds 2 patents. 郑秀华，于原长春地质学院,现吉林大学地学部，获探矿工程学士和硕士学位，于中国 地质大学（北京）获地质工程博士学位。她的硕士论文涉及泡沫剂及其在钻井中的应用，博 士论文则为欠平衡钻井及其优化设计。她于 1993 年在探矿工程研究所负责煤层气压裂液和 钻井液的研究，后调入中国地质大学（北京）从事钻/完井液和地热的教学与研究工作，发 表 40 多篇论文，主编或参编 4 本公开发表教材，1 本校内教材，并获 2 项专利。

The address: 郑秀华，博士、教授 中国地质大学（北京）工程技术学院 北京市海淀区学院路 29 号 100083 Tel.: 010-82321976 Fax: 010-82321976 Mobile: (86) 15911062856

E-mail: [email protected] [email protected] Prof. Dr. Xiuhua Zheng School of Engineering and Technology China University of Geosciences (Beijing) 29 Xueyuan Road Beijing, 100083 P.R.China Tel.: 010-82321976 Fax: 010-82321976 Mobile: (86) 15911062856

E-mail: [email protected] [email protected]

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Contents CHAPTER 1 INTRODUCTION TO DRILLING FLUIDS ................................................... 8 1.1 The Definition of Drilling Fluids（钻井流体定义） ................................................. 8 1.2 The Well Circulation System（钻井循环系统） ....................................................... 8 1.3 The Principal Functions(主要功能) ......................................................................... 9 1.4 Properties of Drilling Fluids（钻井液性能） ......................................................... 12 1.5 Principal Components of Drilling Fluids（钻井液主要成分） ................................. 13 1.6 Drilling Fluid Des ign and Selection（钻井液的设计与选择） ................................. 14 CHAPTER 2 THE PROPERTIES AND EVALUATION OF DRILLING FLUIDS ................ 15 2.1 Density(密度) or Mud Weight(比重)...................................................................... 15 2. 2 Viscosity and Gel Properties(粘度和凝胶性能)...................................................... 16 2.3 API Filtration（API 失水） ................................................................................. 19 2.4 Determination of Gas, Oil, and Solids Content（水、油与固相含量的测定） ........... 20 2.5 Bentonite Content of Mud..................................................................................... 21 2.6 The API Sand Test（含砂量）.............................................................................. 22 2.7 Hydrogen Ion Concentration (pH 值的确定)........................................................... 23 2.8 Filtrate Analys is(滤液分析) .................................................................................. 23 2.9 Resistivity(电阻) ................................................................................................. 28 2.10 Electrical Stability of Emuls ions (乳状液的电稳定性)........................................... 29 2.11 Treatment of Make-up Water (配浆水的处理)....................................................... 29 2.12 Pilot Testing ...................................................................................................... 30 CHAPTER 3

CLAY MINERALOGY AND THE COLLOID CHEMISTRY OF DRILLING

FLUIDS ......................................................................................................................... 32 3.1 Characteristics of Colloidal Systems(胶体特性)...................................................... 32 3.2 Clay Mineralogy(粘土矿物学).............................................................................. 34 3.3 The Colloidal Chemistry of Clay Minerals(粘土胶体化学)....................................... 44 3.4 Interactions of Components in Drilling Fluids(钻井液中各种组分之间的作用) ......... 57 CHAPTER 4 RHEOLOGY AND HYDRAULICS OF DRILLING FLUIDS ......................... 59 4.1 Rheology(流变学) ............................................................................................... 59 4.2 Rheological Models(流变模式)............................................................................. 61 4.3 Measurement of Rheological Properties（流变特性的测量） .................................. 69 4.4 Pressure Drop Modeling（压降模型） .................................................................. 69 4.5 Rheologieal Properties Required for Optimum Performance（流变特性与优化钻井）74 4.6 The Importance of Hole Stability(稳定孔壁的重要性)............................................. 77 CHAPTER 5 THE FILTRATION PROPERTIES OF DRILLING FLUIDS ........................... 80 5.1 Filtration and Filtration Procedures（失水和失水过程）......................................... 80 5.2 The Static Filtration and Affecting Factors（静滤失及其影响因素） ....................... 81 5.3 The Filter Cake(滤饼) .......................................................................................... 85 5.4 Dynamic Filtration(动失水) .................................................................................. 90 6

CHAPTER 6 MAKE-UP MATERIALS AND ADDITIVES FOR DRILLING FLUIDS ......... 92 6.1 Water(水) ........................................................................................................... 92 6.2 Bentonite(膨润土) ............................................................................................... 92 6.3 Materials to Increase Density(加重材料)................................................................ 94 6.4 Inorganic Chemical Additives(无机处理剂)............................................................ 98 6.5 Polymers(聚合物) ..............................................................................................100 CHPAT ER 7 WATER BASE DRILLING FLUID ............................................................. 118 7.1 Classification of Bentonite Drilling Fluid Systems(膨润土钻井液体系分类)............. 118 7.2 Deflocculants Used in Dispersed Systems .............................................................. 119 7.3 Dispersed Non-Inhibited Systems(分散非抑制体系) ..............................................122 7.4 Dispersed Inhibited Systems(分散型抑制体系) .....................................................123 7.5 Non-Dispersed Non-inhibited Systems(不分散非抑制性体系) ................................129 7.6 Non-Dispersed Inhibited Systems(不分散抑制体系) ..............................................132 CHAPTER 8 PROBLEMS RELAT ED TO DRILLING FLUIDS ........................................138 8.1 Borehole stability(井壁稳定) ...............................................................................138 8.2 Loss Circulation（井漏） ...................................................................................142 8.3 Drilling String Sticking（卡钻） .........................................................................146 CHAPTER 9 SOLDI CONTROL ...................................................................................153 9.1 Solid Contained in Drilling Fluid(钻井液中的固相) ...............................................153 9.2 Contents and Purposes of Solid Control(固控的内容和目的) ..................................157 9.3 Solid Control Equipment(固控设备) .....................................................................158 9.4 Arrangement of Solids Control Equipment System(固控设备体系组合的原则).........167 9.5 Evaluation of Efficiency of Solids Control Equipemnt(固控设备效率评价) ..............169 CHAPTER 10 THE NEW DRILLING FLUID TECHNOLOGY...........................................175 10.1 Silicate Drilling Fluid(硅酸盐钻井液).................................................................175 10.2 Mixed Metal Hydroxide(正电胶钻井液) .............................................................177 10.3 Polyol Technology Systems(聚合醇钻井液) ........................................................178 10.4 Micro-bubble (Aphron) Drilling Fluid(可循环微泡沫钻井液) ...............................179 10.5 Formate Drilling Fluid（甲酸盐钻井液）...........................................................181 10.6 Non-Invasive Drilling Fluid（无侵害钻井液） ...................................................183 10.7 High-performance Water-Based Drilling Fluid-Polymeric Amine Drilling Fluid (HPWBM-聚胺钻井液) ...........................................................................................187 References ..............................................................................................................190

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CHAPTER 1

INTRODUCTION TO DRILLING FLUIDS

This chapter introduces, 1) The Definition of Drilling Fluid; 2) The Well Circulation System; 3) Functions of the Drilling Fluid; 4) Properties of drilling fluids; 5)Principal Components of Drilling Fluids; 6) Drilling Fluid Selection.

1.1 The Definition of Drilling Fluids（钻井流体定义） The term drilling fluid（钻井液） encompasses all of the compositions used to aid the production and removal of cuttings from a borehole in the earth. This broad definition purposely places no restriction on the type of tools employed nor on the objective. Some specific examples of the application of drilling fluids are: water(水 ) poured into the hole while boring a foundation footing with an auger; air（空气） introduced to blow cuttings from a blast hole; mud（泥浆） made twice as heavy as water to control tectonic forces in mineral exploration; foam（泡沫） as a conveyor of cuttings from a hole being drilled for water in glacial drift; bentonite slurry（膨润土

泥浆） employed to maintain a stable wall while excavating a cutoff trench; and a mixture of emulsifier（乳化剂）s, stabilizers（稳定剂）, gellants（胶凝剂） and sealants（封堵剂） in an oil base（油基） used to drill for corrosive gases at temperatures above 260℃. Drilling fluids technology is potentially useful in all types of earth excavation. Drilling Fluid Technology involves the sciences of geology, chemistry, and physics, and the skills and applications of engineering. Its goal is the utilization of available equipment and materials to attain at lowest cost the desired objective of earth excavation.

1.2 The Well Circulation System（钻井循环系统） A schematic of the well circulatory system is shown in Figure1-1. The mud pump draws mud in through the suction line from the mud pits and sends it out to the discharge line. The discharge line carries the mud into the standpipe, which runs vertically up one leg of the derrick. The mud exits the standpipe into a strong, flexible, reinforced rubber hose called the rotary hose or Kelly hose. The rotary hose joins the swivel at the gooseneck. From the swivel, the mud flows down through the kelly (or top drive), into the drillstring, mud motor (if present), and the rest of the BHA. Mud emerges from the drill pipe at the bottom of the borehole where the drill bit is grinding away at the rock formation. Now the mud begins the return trip to the surface carrying the pieces of rock, called cuttings, which have been scraped off the formation by the bit, up the annulus, and out of the mud return line. The return line deposits the mud over a vibrating screen called the shale shaker. The shale shaker screens out the larger cuttings and, in some cases, dumps the cuttings into the reserve pit; however, offshore, and in environmentally sensitive areas, the shale shaker dumps the cuttings into a receptacle. At the end of this process, clean mud drains back into the mud tanks (sometimes passing through de-gassers first). Some of the cuttings are taken to be examined by geologists for clues about what is going on deep down inside the well.

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Fig. 1-1 The well circulation system

1.3 The Principal Functions(主要功能) The rotary drilling process and the principal functions of the drilling fluid are related to the mechanical processes of drilling a hole and to reactions with the formations. 1.3.1 Removal of cuttings（携带岩屑） from the bottom of the hole One of the most important functions of the drilling fluid is to efficiently remove the freshly drilled cuttings（岩屑） from the bit and transport them in the annular space between the drill pipe and the hole to the surface, where they can be removed. The ability of the fluid to achieve this objective is dependent to a degree on the annular velocity（环空流速）, which is the speed at which the fluid is pumped up the annulus of the well. For the cuttings to move up the well the annular velocity should be greater than the slip velocity （滑动速度） of the cuttings. Slip velocity is basically the rate at which a cutting will settle through a moving fluid and is dependent on the size, shape and density of the cutting, and on the flow properties of the fluid. Viscosity（ 粘度）, is the resistance of the fluid to flow and considerably influences the carrying capacity（携屑能力） of the fluid. There is an upper limit to the annular velocities achievable due to limitations of the capacity of the pumps, and due to hole erosion. When these limitations are reached the viscosity of the fluid has to be increased. The density（密度） of the fluid has a buoyant effect on the cutting particle so that an increase in density will also increase the carrying capacity. 1.3.2 To suspend （悬浮）cuttings and weighting material when circulation is interrupted The fluid should have the property to form a reversible gel structure（凝胶结构） when it is 9

stationary, so that the cuttings and weighting material（加重材料） remain suspended. The structuring should be reversible so that re circulation can be easily established. The cuttings should also be easily removed at the surface by the solids removal equipment. 1.3.3 Control subsurface pressures The formations are composed of solids of varying porosity（孔隙度）, where the pores are filled with liquids or gases. The rock and pore fluids（孔隙流体） are under pressure arising from the rocks overlying them and from movements of the earth's crust. The column of drilling fluid in the hole will exert a hydrostatic pressure（静液压力） proportional to the depth of the hole and the density of the fluid. This pressure is used to control the flow of gas, oil or water from the pores and makes an important contribution to the stability of the well bore. The flow of the drilling fluid during circulation and movement of the drill string in and out of the hole creates pressure differentials （压差） that are functions of the flow properties of the fluid and the rate of circulation or speed of drill pipe movement. These pressure effects also have to be taken into account when calculating pressures on the formation. 1.3.4 Isolate the fluids from the formation Because of safety considerations, the hydrostatic pressure exerted by the drilling fluid in the well is usually designed to be greater than the pressures existing in the formation. If this were not so, the well could blow out（井喷） if the bit penetrated porous rocks containing brines or hydrocarbons. Under these conditions the drilling fluid will try and penetrate the rock as a whole fluid, or will form filter cakes( 滤饼 ) and the filtrate will penetrate materials have to be incorporated in the drilling fluid to minimise these effects. Whole Fluid Loss（全孔漏失）: There may be highly permeable or fractured formations that will allow the entry of whole drilling fluid if there is a pressure imbalance. The solids that are normally in the fluid may not be large enough to bridge the passages and formation sealing agents, commonly called lost circulation materials（堵漏材料） are added. Filtrate Loss （滤液漏失） : The components in the drilling fluid are chosen so that it is difficult to filter. The solids in the mud form a thin low permeability filter cake that will reduce the amount of fluid permeating into the pore spaces. The filtration properties （ 滤失 特性） of drilling fluids are measured under carefully controlled conditions and can be adjusted by controlling the type and quantity of colloidal material and by special additives. It has been repeatedly shown in the field that a low fluid loss has reduced drilling problems. Conversely, a high fluid loss mud can deposit a thick filter cake on the walls of the hole. This will restrict the passage of tools and will allow excessive amounts of filtrate（滤液） to pass into the formation which may give rise to bore hole instability. 1.3.5 Cool and lubricate the bit and drill string（冷却和润滑钻头和钻具） During the drilling operation, a considerable amount of heat is generated by the frictional forces of the rotating bit and drill string. This heat cannot be totally absorbed by the formation and must be conducted away by the drilling fluid. In addition, the current trend towards even deeper and hotter holes places increased importance on this function. A vast amount of this heal is lost on the surface, with a relatively cool drilling fluid being returned back down the hole. Lubrication is obtained through the deposition of a slick wall cake, and through the use of various, specially formulated additives. Additions of diesel or crude oil may also prove beneficial,

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but this practice is becoming less common due to ecological restrictions. 1.3.6 Support part of the weight of the drill and casing string（支撑钻杆和套管部分重量） The natural buoyancy of a drilling fluid aids in supporting part of the weight of the drill string or the casing string. The degree of buoyancy is proportional to the fluid density. Any increase in fluid density creates an increase in the buoyancy factor, and reduces the load on the surface equipment. The importance of this particular function becomes more apparent as depths increase. 1.3.7 Maximise penetration rates（提高机械钻速） The drilling fluid is so intimately involved in the drilling process that it is inevitable that a wide range of fluid properties will influence the rate of penetration, apart from the mechanical considerations, such as the type of bit, weight on the bit and rate of rotation. Fluid properties, such as low viscosities at high shear rates, low solids, high fluid loss and lower densities than are required to balance pore pressure, all contribute to faster penetration rates. It can be seen that some of the properties, such as high fluid loss and under balance fluid dens ities are contradictory to the properties required for a stable hole, and a compromise must be reached. 1.3.8 Control corrosion rates（控制腐蚀速率） The fluid should be non-corrosive to the drill pipe, casing and drilling equipment. Additives may be used that will specifically give protection, particularly in the highly corrosive environments of hydrogen sulphide and carbon dioxide. 1.3.9 Protect the formation（保护地层） The drilling fluid will come into intimate contact with the formations being drilled. If a stable hole is to be obtained, then interactions between the fluid and the formations should be minimal. For example, if a salt section is to be drilled, then the aqueous phase should be saturated with salt, to prevent wash-outs occurring. Some shale （泥页岩） formations are sensitive to fresh water （水敏） and undergo significant changes in mechanical properties that may result in an enlarged hole or bore hole collapse. An oil based fluid or an inhibited water based fluid（抑制性水基钻井 液） should be used to protect these formations. The porous zones that contain gas or oil should be penetrated with a fluid that will not irreversibly seal the porous passages when the hydrostatic pressure is lowered in order to evaluate the zone. 1.3.10 Secure maximum hole information（保证钻孔信息完全） An important objective in drilling a well is to secure the maximum amount of information about the types of formations being penetrated and the fluids or gases in the pores. This information is obtained by analysis of the cuttings, dissolved gases or oil, and by electric logging technology. The cuttings should be well preserved and not disintegrated and should be transported up the hole efficiently, so that the sample is representative of the depth at which it originated. It should be possible to easily separate and analyse gases or oil dissolved in the fluid. Also the fluid should have a defined resistivity so that satisfactory electric well logs can be obtained. 1.3.11 Transmit hydraulic energy to tools and bit（向钻具和钻头传递水力能） Hydraulic energy provides power to mud motor(泥浆马达 ) for bit rotation and for MWD

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(measurement while drilling 随钻测井 ) and LWD (logging while drilling 随钻测井 ) tools. Hydraulic programs base on bit nozzles sizing for available mud pump horsepower to optimize jet impact at bottom well. 1.3.12 Facilitate cementing and completion（有助于注水泥和完井） Cementing is critical to effective zone and well completion. During casing run, mud must remain fluid and minimize pressure surges, so fracture induced lost circulation does not occur. Mud should have thin, slick filter cake, wellbore with no cuttings, cavings or bridges. 1.3.13 Minimize impact on environment（减少环境影响） Mud is, with varying degree, toxic. It is also difficult and expensive to dispos e of in an environmentally-friendly manner. 1.4 Properties of Drilling Fluids（钻井液性能） The large number of functions that have to be performed has inevitably led to the formulation of complex systems, with at least some of the complexity arising from the different environments encountered in various geological situations. The dominant properties that should be controlled follow from the functions of the fluid. 1.4.1 Density（密度） The correct drilling fluid density is dependent on the down hole formation pressures. Strong, competent formations may be drilled with air, but over-pressured shales and high pressure formations may require a fluid with a specific gravity of up to 3.0. The density is adjusted by soluble salts or by the addition of solids, termed weighting agents. 1.4.2 Viscous or flow properties（粘度或流动性能） These will be dependent on the depth of the hole and the annular velocities obtainable. In the upper hole, water alone may be sufficient, but at greater depths more viscous fluids are required. Deep wells, angled wells, high penetration rates and high temperature gradients all create conditions requiring close attention to the flow properties. 1.4.3 Fluid loss control（漏失控制） This is a fundamental property of the drilling fluid and becomes important when porous formations are being drilled, particularly when those formations may contain gas or oil. Special consideration may have to be given to the high temperature and high pressure fluid loss in particular conditions. 1.4.4 Formation protection（保护地层） The chemistry and composition of the fluid must be such that there is minimal interaction with the formation. Zones of salt, anhydrite (CaSO4 ) dolomite, limestone, shale and sand may be encountered. Each zone differs in its chemical and mechanical properties and each may require different and special drilling fluid properties.

12

1.4.5 Temperature tolerance(抗温性) Temperatures increase with depth quite rapidly in certain areas. The additives and properties must be chosen so that they are stable at the down-hole temperatures. 1.4.6 The other related properties The Determination pH value and alkalinity, filtrate analysis, liquids and solids content, methylene blue test(亚甲基蓝实验 ) for Cation Exchange Capacity（阳离子交换容量） and bentonite content, sand content, electrical conductivity, lubricity, electrical stability of emulsions, corrosiveness.

1.5 Principal Components of Drilling Fluids（钻井液主要成分） Drilling fluids can be classified on the basis of a principal component. These components are (1) water, (2) oil, and (3) gas. Frequently two-and sometimes all three-of these fluids are present at the same time, and each contributes to the properties of the drilling fluid. This general classification is shown in Table 1-1. Table 1-1 Classification of Drilling Fluids According to Principal Constituent Gas Dry gas: Air, natural gas, exhaust gas, combustion gas Mist: Droplets of water or mud carried in the air stream Foam: Air bubbles surrounded by a film of water containing a foam-stabilizing surfactant Stable Foam: Foam containing film-strengthening materials, such as organic polymers and bentonite

Water

Oil

Fresh water:

Oil: Diesel or crude

Solution: True and colloidal, i.e., solids do not separate from water on prolonged standing. Solids in solution with water include: 1. Salts, e.g., NaCl, CaCl2 2. Surfactants, e.g., detergents, flocculants 3. Organic colloids, e.g., cellulosic and acrylic polymers

Oil mud: A sable oil-base drilling fluid contains: 1. Water-emulsifying agents 2. Suspending agents 3. Filtration-control agents Contains cuttings formations drilled

from

the

M ay contain barite to raise density

Emulsion: An oily liquid maintained in small droplets in water by an emulsifying agent, e.g., diesel oil and a film-stabilizing surfactant Mud: A suspension of solids (e.g., clays, barite, small cuttings) in any of the above liquids, with chemical additives as required to modify properties

When the principal constituent is a liquid (water or oil), the term mud is applied to a suspension of solids in the liquid. Water muds and oil muds are thus characterized. The presence of both liquids together results in an emulsion(乳化液 ), provided there is agitation and the presence of a suitable emuls ifying agent. The chemical nature of the emulsifying agent determines whether that oil is emulsified in the water (usually called an oil emulsion mud), or whether the water is emulsified in the oil (usually called an invert emulsion).

13

1.6 Drilling Fluid Design and Selection（钻井液的设计与选择） The task of selecting the proper fluids for each particular situation is the job of the mud engineer, who is educated in the functions and properties of drilling fluids, and who acquires in the field an expertise to choose the right fluids for the right applications, keeping in mind the restrictions of expense, time, and performance. Drilling fluids ranging widely in composition and properties are available for selection. Density of the drilling fluid, which is often the determining factor in the selection, can vary from the density of air to two-and-one half times the density of water, as is illustrated in Fig.1-2.

Fig. 1-2 Drilling fluids can be prepared ranging in density from that of air to 2 1/2 times that of water

1.6.1 Mud Selection Among the many factors to consider when choosing a drilling fluid are the well’s design, anticipated formation pressures and rock mechanics, formation chemistry, the need to limit damage to the producing formation, temperature, environmental regulations, logistics, and economics. To meet these design factors, drilling fluids offer a complex array of interrelated properties. Five basic properties are usually defined by the well program and monitored during drilling: rheology, density, fluid loss, solids content and chemical properties. For any type of drilling fluid, all five properties may, to some extent, be manipulated by using additives. However, the resulting chemical properties of a fluid depend largely on the type of mud chosen. And this choice rests on the type of well, the nature of the formation to be drilled and the environmental circumstances of the well. Exercise One  The definition of drilling Fluids  Functions of the drilling Fluids  

Principal components of drilling fluids Properties related to the effective functions of the drilling fluids

14

CHAPTER 2

THE PROPERTIES AND EVALUATION OF DRILLING FLUIDS

This chapter introduces Drilling Fluid Properties related to its performances: 1) Density; 2) Mud solid and liquid content; 3) Bentonite Content of Mud; 4) The API Sand content; 5) Viscosity; 6) Gel strength; 7 ) API filtration; 8) pH determination. 2.1 Density(密度) or Mud Weight(比重) Density(密度), or Mud Weight(比重) is weight per unit of volume. Once the density is determined it may be expressed in any convenient unit; for example, in pounds per gallon (lb/gal or ppg), pounds per cubic foot (lb/ft3), Specific Gravity (SG) (g/cm3), or in pressure gradient as pounds per square inch per 1,000 feet(psi/1,000 ft) of mud in the hole. The latter unit is most convenient because it may be readily used to calculate the hydrostatic head of the mud column for any depth of hole in the same units in which the pump pressure and the reservoir or formation fluid pressure are calculated. This facilitates control when excessive formation pressure or lost circulation is encountered. The conversion factors are as follows: 3

Specific Gravity (SG) (g/cm ) =

lb / gal lb / ft 3  8.33 62 .3

2-1

3 Mud gradient in psi/ft = lb / ft  lb / gal  SG  0.433 144 19.24

Mud gradient in kg/cm /m = SG  0.1 2

2-2 2-3

The mud balance (Fig.2-1) provides the most convenient way of obtaining a precise volume. It consists of a supporting base, a cup, a lid, and a graduated arm carrying a sliding weight. A knife edge on the arm rests on the supporting base.

Fig.2-1. Mud Balance 1-Arm; 2-Knife; 3-Cup; 4-Lid of the cup; 5-Calibration tank; 6-sliding weight(rider); 7- Base; 8- Fulcrum

The procedure for measuring the density of the mud is as follows: a.

Set up the instrument base so that it is approximately level.

b. Fill the clean, dry cup with the mud to be weighed. c. Place the lid on the cup mud seat it firmly but slowly with a twisting motion. Be sure 15

some mud runs out of the hole in the cap. d. With the hole in the cap covered with a finger, wash or wipe all mud from the outside of the cup and arm. e. Set the knife on the fulcrum and move the sliding weight along the graduated arm until the cup and arm are balanced. f.

Read the density of the mud at the left-hand edge of the sliding weight. Make appropriate corrections when a range extender is used.

g. Read the result to the nearest scale division, in lb/gal, lb/ft3 , SG, or psi/1,000 ft of depth. Wash the mud from the cup immediately after each use. It is absolutely essential that all parts of the mud balance be kept clean if accurate results are to be obtained. Example 1: If the mud reading is 1.20 SG, then it equals 10.0 lb/gal= 74.8 lb/ft 3 = 519 psi/1,000 ft of depth. Calibrating the Mud Balance: a.

Fill the cup with pure water.

b. Replace the lid and wipe dry. c. Set the sliding weight at 8.33 and set the knife edge of the balance on the fulcrum. d. If the weight and cup do not balance in level position, add or remove shot as required, or adjust the calibration screw at the end of the arm. Shot may be added or removed by removing the screw in the shot chamber at the end of the graduated arm. e.

If clear water gives a reading less than 8.3, add the difference between 8.3 and the reading

to the mud weight when the test is made, vice versa. Example 2: If clear water weighs 8.1 lb/gal, and the mud reading immediately afterward is 10.5, then adding 0.2 to 10.5 gives 10.7 lb/gal as the correct weight. Density and Pressure Control（密度与压力控制）. The formation pressure must be properly controlled in drilling process therefore downhole troubles such as blowout, loss of circulation, formation collapse and stuck pipe can be avoided, the bearing formations effectively protected and the drilling operations accomplished safely and smoothly. 2. 2 Viscosity and Gel Properties(粘度和凝胶性能) 2.2.1 Marsh Funnel（马氏漏斗） The Marsh Funnel is useful on the drilling rig, where it enables the crew to periodically report the consistency（粘度 /稠度） of the mud, so that significant changes may be noted by the mud engineer. It consists of a funnel and a measuring cup (Fig.2-2), and gives an empirical value for the consistency of the mud. The test procedure is to fill the funnel to the level of the screen and to then observe the time (in seconds) of efflux of 946ml (1quart).The number obtained depends partly on the effective viscosity at the rate of shear prevailing in the orifice, and partly on the rate of gelation. The time of efflux of fresh water at 21  3 ℃ is 26  0.5 seconds.

Fig.2-2 Marsh Funnel

16

2.2.2 Direct-Indicating Viscometers(直读式粘度计) These instruments are a form of concentric cylinder viscometer that enables the variation of shearing stress（ 剪切应力） with shear rate（剪切速率） to be observed. The essential elements are shown in Figure 2-3，2-4. A bob suspended from a spring（弹簧） hangs concentrically in an outer cylinder（外筒）. The test procedure is to lower the assembly to a prescribed mark（刻线） in a cup of mud, and the outer cylinder rotated（旋转） at a constant speed. The viscous drag（ 粘滞力） of the mud turns the bob until balanced by the torque in the spring. The deflection（偏转角） of the bob is read from a calibrated dial（刻度盘、标度盘） on the top of the instrument, which thus provides a measure of the shear stress at the surface of the bob.

Fig.2-3 Schematic diagram of the direct indicating viscometer. The deflection in degrees of the bob is read from the graduated scale on the dial

Fig.2-4 Fann direct indicating viscometer

The 6 speed viscometer is a motor driven rotational-type viscometer. For measurements, a mud is contained in the annular space between two cylinders. The outer cylinder, or rotor sleeve

（转子套筒）, is driven by a motor and can rotate at a designed constant RPM. The rotation of the rotor sleeve in the mud produces a torque on the inner cylinder（内筒，浮筒）, or bob. A torsion spring（ 扭力弹簧） restrains the movement of the bob, and an attached graduated dial indicates its 2 displacement（位移）, l dial reading=5.11 dynes/cm shear stress. The viscometer has 6 rotational speeds -- 3 rpm, 6 rpm, 100 rpm, 200 rpm, 300 rpm and 600 rpm, 1rpm= 1.703s -1 . Gel Strength: el strength at 10 seconds G10" and that at 10 minutes G10' can be measured by the following steps: a.

Using the same sample in the viscometer cup as in PV and YP measurements, stir the sample at 600 rpm for 10 seconds. b. Let the sample to stand undisturbed for 10 sec. Turn on the viscometer at 3 rpm and take the maximum reading attained  3 as initial gel strength（初切） Gl0" in lb / 100 ft , or 2

1  3 in Pa. 2 c. Restir the mud sample for 10 seconds at 600 rpm and wait for 10 minutes. Start the 17

viscometer at 3 rpm and record the maximum reading attained

（终切） G10' in lb / 100 ft 2 , or

 3 as final gel strength

1  3 in Pa. 2

2.2.3 Calculation of Parameters 2.2.3.1 Bingham Model-Plastic Viscosity,  p , Yield Point,  0 , and Apparent Viscosity,  a :

 p  600  300 , mPa  s

(cp)

 0  0.511(300   p )  0.511(2300  600 ), Pa 1 2

a    600 , mPa  s (cp)

2-4 2-5 2-6

At other rotor speeds, the apparent viscosity,  a , is given by:

a 

300 N , mPa  s N

(cp)

2-7

2.2.3.2 Power Law Model-Flow Behavior Index, n and Consistency Index, K :

n  3.32 lg(600 / 300 )

2-8

K  (0.511300 ) / 511n , Pa  s n

2-9

Example 3: A mud sample in a rotational viscometer equipped with a standard torsion spring gives a dial reading of 46 when operated at 600 rpm and a dial reading of 28 when operated at 300 rpm. Compute the apparent viscosity of the mud at each rotor speed. Also compute the plastic viscosity and yield point. Solution: Use of Eq. 2-6 for the 300-rpm dial reading gives :

a 

300 N 300 (28)   28cp (mPa∙s) N 300

Similarly, use of Eq. 2-6 for the 600-rpm dial reading gives

a 

300 (46)  23cp (mPa∙s) 600

Note that the apparent viscosity does not remain constant but decreases as the rotor speed is increased. This type of non-Newtonian behavior is shown by essentially all drilling muds. The plastic viscosity of the mud can be computed using Eq. 2-4:

P  600  300 46  28  18cp (mPa∙s) The yield point can be computed using Eq. 2-5:

 0 300   p  28  18  10lbf / 100 ft 2  0.511300   p Pa

18

2.3 API Filtration（API 失水） API（美国石油学会） filtration can be measured using API filtration press (Fig.2-5 Low Pressure filter tester 低压失水仪 ) under a pressure of 100  1.0 psi (690  6.9kPa ) applied with nitrogen gas and a proper 9 cm filter paper. The measurement procedure can be done as follows: a. Be sure each part of the cell is clean and dry, and that the gaskets（密封圈） are not distorted or worn. Pour the sample of mud into the cell and complete the assembly with the filter paper in place. b. Place a dry graduated cylinder under the drain tube to receive the filtrate（滤出液） . Close

the

relief

valve

and

adjust

the

regulator

so

that

a

pressure

of

100  1.0 psi (690  6.9kPa) is set up in 30 seconds or less. The test period begins at the time of pressure application. c. Begin timing with timer. At the end of 30 minutes, read the volume of filtrate. Shut off the flow through the pressure regulator and open the relief valve carefully. The time interval, if other than 30 minutes, shall be reported. 3

d. Report the volume of filtrate in cubic centimeters (to 0.1cm ) as the API filtrate. Report at the start of the test the mud temperature. Save the filtrate for appropriate chemical testing e.

if necessary. Disassemble the cell, discard the mud, and use extreme care to save the filter paper with a minimum of disturbance to the cake. Rinse the filter cake on the paper with a gentle stream of water, or with diesel oil in the case of oil mud. Measure the thickness of the

f.

filter cake, and report the thickness in millimeters. Describe the quality of the mud cake using simple technical words.

Fig.2-5 Low Pressure filter tester

Example 4: Using the following data obtained using an HTHP filter press, determine the spurt loss and API water loss. Time(min)

Filtrate Volume(cm3 )

1.0

6.5 19

7.5

14.2

Solution: The spurt loss of the cell can be obtained by extrapolating to zero time us ing the two data points given:

6. 5 

14.25  6.5 1  2.07 cm 3 7. 5  1

However, since the standard API filter press has twice the cross-sectional area of the HT HP 3 filter press, the corrected spurt loss is 4.14 cm . The 30-min filtrate volume can be computed using Eq. 2-10. 3

V30 = 2(V7.5 - Vsp ) + Vsp = 2(14.2-2.07)+2.07 = 26.33 cm Adjusting for the effect of filter press cross-sectional area, an API water loss of 52.66 cm3 at the elevated temperature and pressure of the test can be obtained. 2.4 Determination of Gas, Oil, and Solids Content（水、油与固相含量的测定） Solids contained in drilling fluid include bentonite, weighting materials and drilled solids (drilled cuttings of formation rocks or formation detritus derived from sloughing or collapse). 3

Weighting materials have higher density (usually>4.0g/cm ) and are called high-density solids, 3 and bentonite and drilled solids have lower density (usually<2.7g/cm ) and are called low-density solids. Weighting materials and bentonite are useful solids and drilled solids are useless or harmful solids. 2.4.1 Gas Content A measure of the amount of gas or air entrained in a mud may be obtained by diluting the mud substantially, stirring to release the gas, weighing the gas-free mud, and then back-calculating the density of the gas-free mud without dilution. For example, if

1 is the density of the gas-cut

mud,

 2 the density after diluting 1 volume of mud with 1 volume of water and removing the

gas,

 3 the density of the gas-free, undiluted mud, and  w the density of water, and x is the

volume fraction of gas in the original mud, then:

1 

(1  x)   3 1

2-11

2 

(1  x)   3  1   w 2 x

2-12

Solving for x from the above equations:

x

2  2  1   w

2

2-13

 3 may then be calculated from either of the first two equations. 20

2.4.2 Oil and Solids Content The volume fractions of oil, water, and solids in a mud are determined in a retort such as that shown in Figure 2-6. It is important that any air or gas entrained on the mud be removed before retorting; otherwise, the solids content will be in considerable error. Removal of gas by substantial dilution is undesirable because of the loss of accuracy involved, especially with low-solids muds. Gas may often be removed by adding a defoamer such as aluminum stearate( 硬脂酸铝), or a high molecular weight alcohol, plus a thinner if necessary to break the gel. If, as indicated by the dilution test described above, this procedure fails to remove all the gas, a vacuum should be applied.

Fig.2-6 Retort for determining oil and water content of muds

Portable hand vacuum pumps are available for use in the field. Retorting involves placement of a precise volume of mud in a steel container, and heating it in the retort until no more distillate collects in the graduated cylinder. The volume of oil and water are read in the graduated cylinder, and their sum subtracted from the volume of the mud sample to obtain the volume of solids. The method is rather inaccurate with low solids muds because the result depends on the difference between two large numbers. If the mud contains substantial amounts of salt, the volume occupied by the salt must be subtracted from the volume of solids. The volume of salt (as NaCl) in the mud may be estimated with sufficient accuracy by multiplying the grams of chloride per 100 cm3 of filtrate (determined by titration) by 0.6 and by the volume fraction of water in the mud. 2.5 Bentonite Content of Mud A rapid estimate of the amount of montmorillonite present in a mud or clay can be obtained by means of the methylene blue test. This test measures the amount of methylene blue dye adsorbed by the clays, which is a function of their cation exchange capacity. Since montmorillonite has a much larger cation exchange capacity than other clay minerals, the test has come to be regarded as a measure of the amount of montmorillonite present. 2.5.1 Methylene Blue Test and Cation Exchange Capacity Equipment and Regents: a.

Methylene blue solution: 3.20 g pure grade methylene blue C16H18 N3SCl  3H 2O per liter.

b. Hydrogen peroxide: 3 % solution. c. Dilute sulfuric acid: approximately 5N (13.9 ml 36 N H2 SO4 diluted in 100 ml with deionized water). d. 250 ml Erlenmeyer flask with rubber stopper.

21

e.

Serological pipettes : one 1 ml and one 5 ml.

f. g. h. i.

Burette: 10 ml. Graduated cylinder: 50 ml. Hot plate. Stirring rod.

j.

Filter paper.

Procedure a.

Add 2 ml of mud (or suitable volume of mud that requires 2-10 ml of methylene blue reagent) to 10 ml of water in the 250 ml Erlenmeyer flask. Add 15 ml of 3 % hydrogen peroxide and 0.5 ml of dilute

Fig. 2-7 Procedure of methylene blue test and determination of the end point

sulfuric acid. Boil gently for 10 minutes. Dilute to about 50 ml with distilled water. b. Add methylene blue solution (1 ml=0.01 milliequivalents) from the pipette to the flask. After each 0.5 ml of methylene blue is titrated into the flask, swirl the contents of the flask for about 30 seconds. While the solids are still suspended, remove one drop of liquid with a stirring rod and place the drop on the filter paper. The end point is reached when the dye appears as a greenish-blue ring surrounding the dyed solids. c. When the blue tint spreading from the spot is detected, shake the flask an additional minute and place another drop on the filter paper. If the blue ring is again evident, the end point has been reached. If the ring does not appear or the ring appears temporarily and disappears soon, continue as before until a drop taken after shaking two minutes shows the blue ring firmly evident (see Fig. 2-7). d. Report the cation exchange capacity of the mud as the methylene blue capacity, calculated as follows: No. of ml of methylene blue Methylene blue capacity  , cm3 /cm3 No. of ml of mud 2-14 2.5.2 Bentonite Content of Mud Some chemical additives such as CMC, polyacrylates, lignites and lignosulfonates added in mud for treatments may have methylene blue behavior. In order to eliminate the interference of these additives, a prior treatment with hydrogen peroxide is needed to conduct. If other methylene blue adsorptive materials are not present in significant amounts, the bentonite content of the mud can be estimated as follows: Bentonite 2-15

content

of

mud

in

3

kg/m =14.25×methlylene

blue

capacity Fig.2-8 Srandard API sand sieve

2.6 The API Sand Test（含砂量） The sand content is a measure of the amount of particles lager than 200 mesh present in a mud. Even though it is called a sand test, the test defines the size, not the composition, of the particles. The test is conveniently made in the apparatus shown in Fig.2-8. The mud is first diluted by adding mud and water to the respective marks inscribed on the glass tube. The mixture is then 22

shaken and poured through the screen in the upper cylinder, and then washed with water till clean. The material remaining on the screen is then backwashed through the funnel into the glass tube and allowed to settle, and, finally, the gross volume is read from the graduations on the bottom of the tube. 2.7 Hydrogen Ion Concentration (pH 值的确定) The significant influence of the hydrogen ion concentration on the properties of drilling fluids has long been recognized and has been the subject of numerous studies. Hydrogen ion concentration is more conveniently, expressed as pH, which is the logarithm of the reciprocal of the hydrogen ion concentration in gram mols per liter. Thus, in a neutral solution the hydrogen ion (H+) and the hydroxyl ion ( OH  ) concentrations are equal, and each is equal to 10 -7 . A pH of 7 is neutral. A decrease in pH below 7 shows an increase in acidity (hydrogen ions), while an increase in pH above 7 shows an increase in alkalinity (hydroxyl ions). Each pH unit represents a ten-fold change in concentration. Two methods for the measurement of pH are in common use: (1) a colorimetric method（比色

法） using paper test strips impregnated with indicators, and (2) an electrometric method using a glass electrode instrument. Colorimetric Method（比色法）. Paper test strips impregnated with organic dyes which develop colors characteristic of the pH of the liquid with which they come in contact afford a simple and convenient method of pH measurement. The rolls of indicator paper are dispensed from a dispenser which has the reference comparison colors mounted on its sides. Test papers are available in both a wide-range type, which permits estimation of pH to 0.5 unit, and a narrow -range type, which permits estimation to 0.2 unit of pH. The test is made by placing a strip of the paper on the surface of the mud (or filtrate), allowing it to remain until the color has stabilized (usually less than 30 seconds), and comparing the color of the paper with the color standards. High concentrations of salt in the sample may alter the color developed by the dyes and cause the estimate of pH to be unreliable. Glass Electrode pH Meter（玻璃电极 pH 计）. When a thin membrane of glass separates two solutions of differing hydrogen-ion concentrations, an electrical potential difference develops that can be amplified and measured. The pH meter consists of: (1) a glass electrode_ made of a thin-walled bulb of special glass within which is sealed a suitable electrolyte and electrode; (2) the reference electrode, a saturated calomel cell; (3) means of amplifying the potential difference between the external liquid (mud) and the glass electrode; and (4) a meter reading directly in pH units. Provision is made for calibrating with standard buffer solutions and for compensating for variations in temperature. A special glass electrode (less affected by sodium ions) should be used in measuring the pH of solutions containing high concentrations of sodium ions (high salinity or very high pH). 2.8 Filtrate Analysis(滤液分析) Some chemical tests are made on mud filtrates to determine the presence of contaminants, such as salt or anhydrite, or to assist in the control of mud properties; for example, the test for 23

alkalinity in high pH muds. The same tests can be applied to make-up waters, which in some areas contain dissolved salts which materially affect mud treatment. The equipment generally used for filtrate analys is includes automatic burette, reagent bottle, dropper bottler, casserole, graduated cylinder, graduated pipette, and glass stirring rod. 2.8.1 Alkalinity Determinations(碱度测定) Because the pH scale is logarithmic, the alkalinity of a high pH mud can vary a considerable amount with no measurable change in pH. In highly alkaline systems analysis of the mud filtrate to determine the alkalinity yields more significant results than pH measurement. The procedure for the alkalinity test P f is: a. Measure one or more cubic centimeters of fresh filtrate into a 125-ml Erlenmeyer flask or casserole. b. Add 2 to 3 drops of phenolphthalein indicator solution. If no color develops, P f is 0. If a pink color developsc. Add 0.02 normal (N/50) sulfuric acid from an automatic burette or a pipette, stirring continuously, until the sample turns from pink to colorless. If the sample is so colored with chemicals that this end point is masked, the end point is then taken when the pH drops to 8.3 using the glass electrode pH meter. The number of cubic centimeters of 0.02 normal (N/50) sulfuric acid divided by the cubic centimeters of sample taken is called the "P" alkalinity of the filtrate (Pf). d. To the sample which has been titrated to the "P" end point, add 2 or 3 drops of methyl orange indicator solution. Add standard acid drop by drop from the pipette while stirring until the color of the solution changes from orange to pink. Record as "M," the total volume of acid, in cubic centimeters, used to reach the methyl orange end point, including that of the "P" end point. If the sample is so colored that the change in color is not evident, the end point is taken when the pH drops to 4.3, as measured with the glass electrode pH meter. e.

Report the methyl orange alkalinity of the filtrate, Mf, as the total cubic centimeters of 0.02 normal acid per cubic centimeter of filtrate required to reach methyl orange end point. 2.8.2 Lime Content Estimation(石灰含量测定) Some knowledge of the amount of excess lime present is of considerable value as an aid in controlling the properties of a lime-treated mud. An estimation of lime content can be made based on alkalinity titrations of the filtrate and of the whole mud. The titration of the mud must be made rapidly to permit titration of calcium hydroxide and sodium hydroxide without interference from calcium carbonate. The procedure for estimating the lime content is: a. Measure one cc of mud into a casserole and dilute to about 50 cc with distilled water. A veterinary syringe is satisfactory for measuring even very thick mud, while a pipette may be used for thinnner muds. b. Add 2 to 3 drops of phenolphthalein indicator solution. A pink color develops. c. Add 0.02 normal (N/50) sulfuric acid rapidly from a burette or pipette, stirring continuously, until the sample first turns from pink to the color of the mud. The number of cubic centimeters of 0.02 N acid divided by the cubic centimeters of sample taken is called the P alkalinity of the mud (P m). 24

d. Determine the P alkalinity of the filtrate (P f) according to the method given in the e.

preceding section. Calculate the lime content as follows: 0.26 (Pm -Fw Pf)=equivalent calcium hydroxide (lb/bbl)

2-16

Where: Pm = cc 0.02 N acid for P of mud Pf

= cc 0.02 N acid for P of filtrate

Fw = volume fraction of water in mud 2.8.3 Salt Concentration (Chloride) Test The salt or chloride test is very significant in areas where salt can contaminate the drilling fluid. Salt tests are among the means of detecting these flows. When the chloride content exceeds 6,000 ppm, it may be necessary to alter the mud program. The test is made on a portion of the original filtrate, or on the sample from the alkalinity test to which a pinch of calcium carbonate has been added. The chloride content test procedure follows: a.

Measure a sample of any convenient volume, from one cc to 10 cc, into the casserole and dilute to about 50 cc with distilled water.

b. Add a few drops of phenolphthalein indicator. If a pink color develops, add sulfuric acid until it completely disappears. If phosphates have been added in large quantities, add 10 to 15 drops of calcium acetate solution. c. Add four or five drops of potassium chromate indicator to give the sample a bright yellow color. d. Add standard silver nitrate solution a drop at a time, stirring continuously. The end point of the titration is reached when the sample first changes to orange or brick-red. Calculate the chloride (Cl) content as follows: cc of silver nitrate Cl content in mg per liter or ppm   1,000 cc of sample If in the standard solution, 1 cc=1 mg Cl, or 4.7910 g of AgNO 3 per liter (0.0282 N) or Cl content in mg per liter or ppm 

cc of silver nitrate  10,000 cc of sample

If in the standard solution, 1 cc=10 mg Cl, or 47.910 g of AgNO 3 , per liter (0.282 N) The above method of calculation assumes no change in density of the filtrate with increasing salt concentration. Therefore, the results are correctly expressed in mg per liter but not in ppm. To express the concentration in ppm or percent by weight, use the following: ppm 

mg per liter density of sol., g per cc

percent by wt 

mg per liter 10， 000（density of sol., g per cc）

2-17 2-18

In addition to common salt, which is sodium chloride, salt beds and brines often contain the chlorides of calcium and magnesium. The testing method described determines the amount of "chloride ion" present. The result can be expressed in terms of sodium chloride, or salt, by

25

multiplying by 1.65. 2.8.4 Preservative Concentration(防腐剂含量) Some knowledge of the amount of preservative present in a mud for the prevention of fermentation of starch is necessary. Because paraformaldehyde is frequently used alone and because it is the major constituent of many proprietary preservatives, a method of estimating the formaldehyde content of the mud filtrate is given below. a.

Measure 3 cc of filtrate into a casserole or test tube. Add 2 drops of phenolphthalein indicator solution. If the sample remains colorless, it is acid, and 0.02 normal (N/50) sodium hydroxide solution should be added drop-by-drop with agitation until a faint pink color develops. Then add 0.02 normal (N/50) sulfuric acid drop-by-drop to discharge the

color. b. If the filtrate becomes colored with the first addition of phenolphthale in, add the sulfuric acid dropwise until the color is just dispelled. c. To the neutralized f iltrate add one cc of 4.0 percent sodium sulfite solution. A red color will develop. d. After approximately 30 sec, titrate using a 10 cc pipette with a 0.02 normal (N/50) sulfuric acid until the sample is a very faint pink. Record the amount of acid in cubic e.

centimeters. Repeat the above procedure (3 and 4) using distilled water instead of mud filtrate.

f.

Subtract the cubic centimeters of acid required for the blank determination (5) from the cubic centimeters used for Step 4 and multiply by 0.07 to find the formaldehyde content

in lb per bbl. Preservation test kits equipped only with dropper bottles are widely used for preservative content determination. If the test is carefully made, the resulting values will be in substantial agreement with those found by the above procedure. It should be noted that a sodium sulfite solution deteriorates readily and if older than 30 days should be replaced with fresh solution. The solution is prepared by dissolving 4 g of sodium sulfite in l00 cc of distilled water. 2.8.5 Tests for Hardness and Calcium Concentration By "hard water" we mean water containing dissolved calcium and magnes ium salts. The common evidence of hardness in water is the difficulty of producing a lather in it with soap. As is well understood, drilling clays have low "yields" when mixed in hard water. The harder the water, the more bentonite it takes to make a satisfactory gel mud. While in extreme cases it has been found economical to treat the water chemically before using it for mixing mud, this is not generally true. Frequently, however, where there is a choice of two or more sources of water for the rig, it may be desirable to make a simple test to select the softer of the two. All field men are familiar with the effects on the mud when anhydrite, calcium sulfate, or "gyppy" formations are drilled. Likewise, calcium salts are picked up in drilling cement plugs and sometimes in penetrating sections of limy shale. Any extensive calcium contamination results in abnormally high water loss and fast gel rate. Two methods of testing for calcium are given below. Calcium Sulfate. Some knowledge of the calcium sulfate content is necessary the proper maintenance of gyp muds. Determination of the calcium sulfate content of a mud may be made by the Versenate test using the following procedure: a. Add 5 cc of mud to 245 cc of distilled water. Stir the mixture for 15 minutes and then

26

filter through hardened filter paper. Discard the cloudy portion of filtrate. b. Titrate l0 cc of the clear filtrate to the Versenate end point as described in Versenate Test for Hardness. c. Titrate 1 cc of filtrate of the original mud to the Versenate end point. d. Report the calcium sulfate content in lb/bbl, calculated as follows: Total calcium sulfate, lb/bbl= 2.38 Vt Undissolved calcium sulfate, lb/bbl = 2.38 Vt - 0.48 VfFw Where: Vt = cc of Versenate solution to titrate 10 cc of the filtrate of the diluted mud Vf = cc of Versenate solution to titrate 1 cc of filtrate of the original mud Fw= Volume fraction of water in the mud Estimation of Calcium by Oxalate. When contamination by calcium salts is suspected, the relative amount present can be estimated by a simple test, as follows: a.

Place from 2 to 4 cc of filtrate in a test tube or other convenient clean container.

b. Add about one cc of dilute ammonium oxalate solution. c. The calcium present will be precipitated out of solution and will appear as a milky, while precipitate in the sample. Since this test does not give the calcium content in parts per million, it is general practice to record the calcium content as "trace," "show," "light," and "heavy" calcium concentration. Versenate Test for Hardness: a.

To approximately 50 cc of distilled water in a titration dish add about 2 cc of Hardness Buffer Solution and 5 to 10 drops (0.25 cc to 0.50 cc) of Hardness Indicator Solution. If a red color develops, indicating hardness in the distilled water, add Hardness Titrating Solution (1 cc equivalent to 20 milliequlvalents per liter using 1 cc sample) dropwise until the water first turns to blue. Do not include this volume of titrating solution in calculating

hardness of the sample in Step 4. b. Measure 1 or more cc of sample into the casserole. A pink to wine red color, depending upon the color of the sample, will develop if calcium or magnesium is present. c. Add Hardness Titrating Solution, stirring continuously, until the sample first turns blue. d. The total hardness is calculated as follows:

cc of titrating solution  20  milliequiv alents per liter of (Ca  Mg) cc of sample

cc of titrating solution  ppm of calcium and magnesium as CaCO3 cc of sample  1000 Versenate Test for Calcium: a.

To approximately 50 cc of distilled water in a titrating dish add about a pinch of CalVer II. Then add 1 cc of Calcium Buffer Solution. If a wine red color develops indicating calcium in the distilled water, add hardness titrating solution, 1 cc equivalent to 20 ppm, using 1 cc sample, until a blue color appears. Do not include this volume of titrating solution in calculating calcium of the sample in Step 4.

b. Measure 1 cc of sample into the titrating dish. A wine red color will appear if calcium is present.

27

c. Add hardness titrating solution until the water turns blue. d. The calcium is determined as follows:

cc of titrating solution  20  milliequiv alents per liter of (Ca) cc of sample e.

To determine Mg present subtract equivalents per liter of Ca obtained from equivalents per liter total hardness (Ca + Mg) determined by Versenate Test for Hardness above.

Estimation of Sulfate by Barium Chloride. Acidified barium chloride solution can be used to estimate the sulfate content in a manner similar to that in the use of ammonium oxalate solution for the estimation of calcium, thus: a. Place from 2 to 4 cc of filtrate in a casserole, beaker, or test tube. b. Add a few drops of barium chloride solution. c. Any sulfates present will appear in the sample as a milky, white precipitate. The terms "trace,' "show,' "light ," and "heavy" are to indicate the relative seriousness of the contamination. A more accurate determination of the amount of sulfate can be made in the field with a photo cell apparatus. All of the ions commonly encountered in water may be tested with the device. The Photo Tester. In the photo tester a prefocused beam of light passes through a sample bottle containing the sample and the reagent and falls on a photoelectric cell. This generates a small electric current which can be measured by a microammeter. The current thus measured is referred to a calibration chart to show the amount of a given ion present. 2.9 Resistivity(电阻) Control of the resistivity of a mud and mud filtration while drilling may be desirable to permit better evaluation of formation characteristics from electric logs. The determination of resistivity is essentially the measurement of resistance to electrical current flow through known sample configuration. Measured resistance converted to resistivity by use of a cell constant. The constant is fixed by the configuration of the sample the cell and is determined by calibration with standard solutions of known resistivity. The resistivity is expressed in ohmmeters. Equipment. The measurement of electrical resistivity of the mud and mud filtrate requires: a. A calibrated resistivity cell. b. An instrument or apparatus for measuring the resistance of the sample in the cell. c. A thermometer for measuring the sample temperature. Any type of cell and instrumentation which is sufficiently accurate to permit determination of resistivity within 5 percent of the correct value may be used. If the instrument indicates the sample resistance is ohms, the cell constant must be known. The resistivity in ohmmeters is obtained by multiplying the resistance in ohms, by the cell constant in square meters per meter. If the instrument is a type of direct-reading resistivity meter, the cell constant has been adjusted to a particular value or accounted for in the electrical circuit of the meter. Such an instrument measures the sample resistance and converts it to resistivity so that the reading is taken directly as ohmmeters. For all instruments, the manufacturers' instructions for current source, calibration, measurement, and calculation should be followed. Procedure. Fill the clean, dry resistivity cell with freshly stirred mud or with filtrate. Be sure 28

that no air or gas is entrained in the sample. Connect the cell to the measuring instrument. Measure the resistance in ohms, and using the cell constant or calibration chart, convert to resistivity; or measure the resistivity directly with a direct-indicating resistivity meter. Measure the temperature of the sample to the nearest degree F. Report the mud resistivity R m or filtrate resistivity R mf in ohmmeters to the nearest 0.01 ohmmeter. Report the sample temperature in degrees F. Clean the resistivity cell. Scrub with a brush and detergent solution if necessary. Rinse the cell thoroughly with distilled water and allow it to dry. 2.10 Electrical Stability of Emulsions (乳状液的电稳定性) The electrical stability test indicates the stability of emulsions of water in oil. Equipment. The emulsion tester consists of a reliable circuit using a source of variable ac current, or dc current in portable units, connected to strip electrodes. The voltage imposed across the electrodes can be increased until a predetermined amount of current flows. The measure of emulsion breakdown is indicated by current flow. Relative stability is indicated as the voltage at breakdown point. Procedure. Insert the probe (electrodes) into the drilling fluid to be tested. Choose the voltage range multiplier applicable. Increase the voltage across the electrode until the instrument indicates emulsion breakdown. Record the voltage reading as an electrical stability number. Report the temperature of the sample in degrees F. 2.11 Treatment of Make-up Water (配浆水的处理) In areas where only hard water is available for mixing mud, the yield of the clay can be increased and the water loss decreased by removing the dissolved calcium and magnesium. Soda ash is added to form a precipitate of calcium carbonate while caustic soda will be required to precipitate magnesium as the hydroxide. The quantity of soda ash and caustic needed to soften the water can be estimated from the hardness found by the Versenate titration, as follows:

Lb of soda ash per bbl of water  0.014  me/l of Ca ion Lb of sodium hydroxide per bbl of water  0.018  me/1 of mg Where: me/l is the milliequivalent per liter Treatment with soda ash alone will not remove all of the hardness from a water containing a high concentration of bicarbonate. The alkalinity of such waters must be raised to allow complete removal of calcium by soda ash. The bicarbonate content of the water can be calculated from the alkalinity determined according to the procedure given in "Alkalinity Determination." The estimation of hydroxide, carbonate, and bicarbonate is made from these relations: Let: P = cc 0.02N H2 SO4 required for phenolphthalein end point M = total cc 0.02N H2 SO4 required for methyl orange end point Then when: 29

P = zero, the alkalinity is due to bicarbonate alone P = M, the alkalinity is due to hydroxide alone 2P > M, the alkalinity is due to a mixture of carbonate and hydroxide 2P < M, the alkalinity is due to a mixture of carbonate and bicarbonate The results may be expressed as: a.

Total Alkalinity

M  20 = milliequivalents of total alkalinity per liter b. Carbonate Alkalinity (a) If hydroxide is present, (M - P)  40 = milliequivalents of carbonate alkalinity per liter (M - P)  1200 = parts per million of carbonate (CO3 ) (b) If hydroxide is absent, P  40 = milliequivalents of carbonate alkalinity per liter P  1200 = parts per million of carbonate (CO3 ) c. Hydroxide Alkalinity (2P - M)  20 = milliequivalents of hydroxide alkalinity per liter (2P - M)  340 = parts per million of hydroxide (OH) d. Bicarbonate Alkalinity (M - 2P)  20 = milliequivalents of bicarbonate alkalinity (HCO3 ) per liter (M - 2P)  1220 = parts per million of bicarbonate (HCO3 ) A simple treatment, adequate for most hard make-up waters, is to add enough caustic soda to raise the pH to 9 and then add soda ash equivalent to the total calcium and caustic soda equivalent to the magnesium. The hydroxide, carbonate, and bicarbonate values determined as in the foregoing represent a proper type of water analysis. The application of these procedures to the usual mud filtrate is, however, of doubtful validity because reactions with other soluble components, such as treating agents, do not permit quantitative determinations of carbonate and bicarbonate by simple titration. 2.12 Pilot Testing Certain suggestions as to pilot testing procedures will be helpful as a guide in determining the appropriate treatment to condition a mud. For example, confusion can be avoided by recording the results of pilot tests in field units. An addition of one gram of material to a 350 cc sample of mud is equivalent to an addition of one pound of material per barrel of mud. Additions of liquids can be made as percent by volume and recorded as barrels of liquid per 100 bbl of original mud. It is important when making pilot tests to consider the order and manner in winch materials will be added under field conditions. Considerable variation in results can be obtained by first adding a material as a dry solid and then adding it in solution, or by adding a clay before a chemical thinner as compared to adding it afterward. The order of addition should always be indicated when recording pilot test results. It is convenient to have solutions with water of materials which are normally added through the chemical barrel. A caustic-quebracho solution, for example, can be prepared by dissolving 35 g of caustic soda and 35 g of dry quebracho in a convenient quantity of water and then adding more 30

water to make 350 cc of solution. In a pilot test, 10 cc of this solution added to 350 cc of mud is equivalent to adding 1 lb of caustic soda and 1 lb of quebracho per barrel of mud, along with 3 percent by volume of water. Mixing of a pilot-test sample is also quite important. There is no simple method of duplicating closely the mixing which the mud receives in the course of circulation. Experience has indicated some very general rules when using a high-speed mixer, such as: a. Stir 5 min when adding liquids or inert solids. b. Stir 15 min when adding solids which need only to be dispersed. c. Stir slowly for 30 min (or stir and allow to stand) when adding materials which undergo hydration or enter into chemical reactions which take place slowly. d. Take care to avoid excessive stirring. High-speed shearing may alter the properties of a mud; consequently, the untreated mud should be stirred and tested in the same way as the treated samples. Even though muds of the same type will perform in a somewhat similar manner, at no time will two field muds have exactly the same composition. Pilot testing is therefore frequently helpful in predicting the response of a field mud to a particular treatment or to a particular contamination. In many complex mud systems, however, pilot testing chemical additives without proper heat aging may give misleading values. It is most important to conduct a thorough mud check, evaluate the condition of the mud based on the values obtained, and add treating materials with the knowledge of exactly why each material is added. Discussion 1. 2.

Discuss the relationships between drilling fluid properties and the drilling operation. How does density affect hole stability and penetrate rate?

3. 4.

How does rheology affect the drilling operation? How about the other properties, such as filtration properties, solid contents, pH value, etc.?

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CHAPTER 3

CLAY MINERALOGY AND THE COLLOID

CHEMISTRY OF DRILLING FLUIDS Anyone concerned with drilling fluids technology should have a good basic knowledge of clay mineralogy（粘土矿物学） ， as clay provides the colloidal base of nearly all aqueous muds（水 基泥浆）, and is also used in oil-based drilling fluids（油基泥浆） . Drill cuttings from argillaceous formations become incorporated in the drilling fluid, and profoundly change its properties. The stability of the borehole depends to a large extent on interactions between the drilling fluid and exposed shale formations. Interactions between the mud filtrate（滤液） and the clays present in producing horizons（生产层） may restrict productivity of the well if the wrong type of mud is used. All of these point out the need for the knowledge of clay mineralogy. The drilling fluid technologist should have a basic knowledge of colloid chemistry（胶体化 学） as well as clay mineralogy, because clays form colloidal suspensions（胶体悬浮液） in water, and also because a number of organic colloids（有机胶体） are used in drilling muds. In this chapter it will summarize briefly those aspects of clay mineralogy and colloid chemistry which affect drilling fluid technology. 3.1 Characteristics of Colloidal Systems(胶体特性) Colloids are not, as is sometimes supposed, a specific kind of matter. They are particles whose size falls roughly between that of the smallest partic les that can be seen with an optical microscope and that of true molecules, but they may be of any substance. Actually, it is more correct to speak of colloidal systems, since the interactions between two phases of matter is an essential part of colloidal behavior. Colloidal systems may consist of solids dispersed in liquids (e.g., clay suspensions 粘土悬浮液 ), liquid droplets dispersed in liquids (e.g., emulsions-乳状液 ), or solids dispersed in gases (e.g., smoke-尘雾 ). In this chapter, we shall only be concerned with solids dispersed in water. One characteristic of aqueous colloidal systems is that the particles are so small that they are kept in suspension indefinitely by bombardment of water molecules, a phenomenon known as the Brownian movement.（布朗运动）. The erratic movements of the particles can be seen by light reflected off them when they are viewed against a dark background in the ultramicroscope. Another characteristic of colloidal systems is that the particles are so small that properties like viscosity and sedimentation velocity are controlled by surface phenomena(表面现象). Surface phenomena occur because molecules in the surface layer are not in electrostatic balance（电荷平

衡） ; i.e., they have similar molecules on one side and dissimilar molecules on the other, whereas molecules in the interior of a phase have similar molecules on all sides. Therefore, the surface carries an electrostatic charge(静电荷), the size and sign of which depends on the coordination of the atoms（原子配位） on both sides of the interface. Some substances, notably clay minerals, carry an unusually high surface potential（表面能） because of certain deficiencies in their atomic structure, which will be explained later. The greater the degree of subdivision(分散度) of a solid, the greater will be its surface area per unit weight, and therefore the greater will be the influence of the surface phenomena. For 2

example, a cube with sides one mm long would have a total surface area of 6 mm . If it were 32

subdivided into cubes with one micron sides (1 micron = 1  10 3 mm) there would be 10 cubes, 9

each with a surface area of 6  10 6 mm2 , and the total surface area would be 6  10 3 mm2 . Subdivided again into milli-micron cubes, the total surface area would be 6  10 6 mm , or 6 2

square meters. The ratio of surface area per unit weight of particles is called the specific surface（比表面）. 3

Thus if a 1 cm cube were divided into micron sized cubes, the specific surface would be

6 10 6 / 2.7  2.2 10 6 mm2 / g  2.2m 2 / g , assuming the specific gravity of the cube to be 2.7. Figure 3-1 shows specific surface versus cube size. To put the values in perspective, the size of various particles, expressed in equivalent spherical radii (esr-等效球形半径), are shown at the top. The esr of a particle is the radius of a sphere that would have the same sedimentation rate as the particle. The esr may be determined by applying Stokes' Law (see Chapter 3) to the measured sedimentation rate. The division between colloids and silt; shown in Figure 3-1, is arbitrary and indefinite, because colloidal activity depends (a) on specific surface, which Fig. 3-1 Specific surface of cubes. Assuming varies with particle shape, and (b) on specific gravity of 2.7 surface potential, which varies with atomic structure. A large proportion of the solids in drilling muds fall in the silt size range. These particles are derived either from natural silts picked up from the formation, from larger particles comminuted by the action of the bit, or from barite added to raise the density. Particles in this size fraction are commonly called the inert solids（惰性材料） , but the term is relative, and when present in high enough concentrations, the inert solids exercise a considerable influence on the viscous properties of the mud. Colloids, on the other hand, usually constitute a small proportion of the total solids, but exercise a relatively high influence on mud properties because of their high degree of activity. They may be divided in two classes: (a) clay minerals, and (b) organic colloids, such as starch（淀

粉）, the carboxycelluloses（羧基纤维素）, and the polyacrylamide derivatives((聚丙烯酰胺衍 生物 ). These substances have macro-molecules(高分子 ), or are long-chain polymers(长链聚合 物 ), whose size gives them colloidal properties.

33

3.2 Clay Mineralogy(粘土矿物学) 3.2.1 Introduction The group of minerals classed as clays play a central role in many areas of drilling fluid technology. The clay group can be described chemically as aluminium silicates（硅铝酸盐）. Since the elements that constitute the clays account for over 80% of the mass of the earth (aluminium 8.1%, silicon 27.7% and oxygen 46.6%) it can be readily realised that every stage of drilling a hole brings contact with the clays(粘土 ). The most common formations that are drilled are clays and shales, where the type and quantity of clay minerals present is one of the most important features that determine the chemical and mechanical properties of the rock（岩石的化学和力学性质）. The selection of the drilling fluid is often related to the reactions between the fluid and the rock, as these can influence the stability of the bore hole. Thus, an understanding of clay chemistry is important in the selection of a drilling fluid system and bore hole stability（井壁稳定性）. Clays are often used to derive the viscous flow properties of the fluids. Clays, such as bentonite（膨润土） and attapulgite（绿坡缕石）, are added purposely and formation clays are entrained in the circulating fluid. A large range of chemicals, including those described as "mud conditioning chemicals", are added to control the viscous properties. A full understanding of the chemistry of those chemicals and the clays will enable the engineer to control the fluid properties more effectively. Most reservoir sandstones（砂岩） contain some clay minerals. These may react with the fluids that contact them in such a way as to completely block the formation. Again the structures and reactions of clays are important in the design of fluids that may be in contact with the production zone. 3.2.2 Basic features（基本特征） There are a number of features of the clay minerals that distinguish them as a group. The most important one is the chemical analysis which shows them to be composed essentially of silica（二

氧化硅）, alumina（氧化铝）, water and frequently with appreciable quantities of iron（铁） and magnesium（镁） and lesser quantities of sodium（钠） and potassium. Other properties, such as fine size, large surface area and chemical reactivity of the surface, are related to the structural details. 3.2.2.1 Fundamental building units（基本构造单元） There are two simple building units from which the different clay minerals are constructed. Octahedral layer（八面体层）.This unit consists of two sheets of closely packed oxygens or hydroxyls in which aluminium, iron or magnesium ions（铝离子和镁离子） are embedded in octahedrat coordination. When aluminium is present, only two thirds of the possible positions are filled to balance the structure, which is the gibbsite structure. Al (OH) 3 . When magnesium is present, all the positions are filled and the structure is brucite, Mg (OH) 2 . Often in clays, this layer contains more than one metal ion. See Figure 3-2.

34

Fig. 3-2 Diagrammatic sketch of (a) single octahedral unit, and (b) the sheet structure of the octahedral units

Tetrahedral layer（四面体层）. In each tetrahedral unit（四面体单元）, a silicon atom(硅 原子 ) is located in the centre of a tetrahedron, equidistant from four oxygen atoms, or hydroxyls, if needed to balance the structure. The silica（二氧化硅） tetrahedral groups are arranged to form a hexagonal network, which is repeated infinitely to form a sheet of composition, Si4 O6 (OH)4 , See Figure 3-3. The sheet is viewed from above in Figure 3-4 to show the hexagonal network with a "hole " in the centre.

Fig. 3-3 Diagrammatic sketch of (a) a single silica tetrahedron, and (b) the sheet structure of silica tetrahedrons

Fig. 3-4 The silica chain viewed from above arranged in a hexagonal network

It is the different combinations of these units and modification of the basic structure that give rise to the range of clay minerals with different properties. The two units are the alumina octahedral sheet and the silica tetrahedral sheet. 3.2.2.1 Structures of clay minerals（粘土矿物的结构） The fundamental units of tetrahedral sheets and octahedral sheets can combine with the hydroxyl group of the tetrahedral layer contributing to the octahedral layer. Different combinations and chemical modification have given rise to over 26 different clay mlnerals(粘土矿物 ). The clay minerals are built up by different ratios of silica layer to octahedral layer. The largest group is the 2:1 layer, there are also 2:1:1 minerals and 1:1 minerals. The most important clay

35

minerals of interest to the drilling fluid engineer are kaolin, mica, illite, montmorillonite, sepiolite, attapulgite and chlorite. Examples of these structures are summarised in Table 3-1 and in Figure 3-5.

Fig.3-5 Schematic representation of the structure of the principal clay minerals

Before the structures of the clay minerals can be discussed in any detail, the two mechanisms by which electrical charges（带电） may be developed on the clay surfaces, must be described. 3.2.3 Charges on clay surfaces（粘土表面的电荷） Charges on clay surfaces arise from two mechanisms. One is related to the structure of the clay and is a characteristic of the particular mineral. The other arises from the broken edges. 3.2.3.1 Isomorphous substitution（同晶取代） The idealised combinations of tetrahedrat and octahedral sheets give a structure in which the charges are balanced. However, if a metal ion is replaced by an ion of lower charge valency, a negative charge is created. For example, in the tetrahedral layer（四面体层） , silica may be replaced by iron, or in the octahedral layer aluminium may be replaced by magnesium. The negative charge on the clay lattice is neutralised by the adsorption of a cation（吸附阳离子）. This gives rise to the important property of the clays known as cation exchange capacity(CEC，阳离子 交换容量 ), because the ions of one type may be exchanged with ions of the same or different type. The cation exchange capacity arising from substitutions within the lattice structure does not vary with pH. It is an important characteristic of the clays and varies from mineral to mineral, as shown in Table 3-1. Table 3-1 S ummary of Structure and Properties of the most common clay minerals Properly

Kaolin

Mica

Mint＊

Attap＊ *

Chlorite

36

Layer Type

1:1

2:1

2:1

2:1

2:1:1

Crystal Structure

Sheet

Sheet

Sheet

Sheet

Sheet

Particle Shape

Hexagonal plate

extensive plates

flake

needle

plate

Particle Size M icrons

5-0.5

Large sheets to 0.5

2-0.1

1-0.1

5-0.1

15-25

50-110

30-80

200

140

—

200-800

—

—

Surface Area BET-N 2-M 2/g BET-H 2O- M /g

—

Cation Exchange

3-15

10-40

80-150

15-25

10-40

Low

Low

High

High

Low

Flocculates

Flocculates

Flocculates

Little or none

Flocculates

2

Capacity meq/100g Viscosity in Water Effect of Salts ＊

,

mont=montmoriionite

＊*

attap=attapulgite

This property is often used to characterise clays, shales and drilling fluid and is determined by measurement of the adsorption of a cationic dye, methylene blue （亚甲基蓝）. The result is quoted as the milli-equivalents of dye adsorbed per l00g of dry clay. The pattern of isomorphous substitution varies in the different minerals in the following aspects: （a)

tetrahedral or octahedral substitution

（b)

extent of substitution

（c)

the nature of the exchanged cations, i.e. Na, K or Ca

The replaceability of cations depends on a number of factors such as:- effect of concentration - population of exchange sites - nature of anion - nature of cation - nature of clay mineral This large number of variables creates a complex system to analyse. It has been shown that different ions have different attractive forces for the exchange sites. The relative replacing power +

+

+

++

++

+

of cations is generally Li
37

Fig. 3-6 pH dependent charges on the broken edges of Clay crystals

Thus at low pH values, the broken edges are more positive and at high pH the edges are more negative. One of the reasons for the pH values of drilling fluid to be kept on the alkaline side is to ensure that the clay particles are only negatively charged so that electrostatic interactions are kept at a minimum. Chemical treatment of drilling fluids is often aimed at a reaction with the groups on the broken edges. Since the edge surface is created by grinding or breaking down the clays, chemical treatment costs can be minimised by ensuring that the formation clays are removed as cuttings, rather than broken down at the bit into finer sized particles. 3.2.4 Clay mineral groups（粘土矿物组） There are published lists of over 400 mineral and rock names to describe clay minerals. We will restrict our attention only to a few minerals that are most common and most applicable to drilling fluid technology. 3.2.4.1 Kaolin（高岭土）

Fig.3-7 Diagrammatic sketch of structure of Kaolin

Kaolin is composed of a single tetrahedral sheet and a single dioctahedral alumina sheet, combined so that the tips of the oxygen atoms of the silica tetrahedra and the oxygen and hydroxyl layer of the octahedral layer, form one layer. A diagrammatic sketch of the 1:1 structure is given in Figures 3-5 and 3-7.

38

The charges within the structure are balanced and there are very few lattice substitutions. Very strong hydrogen bonding（氢键结合） exists between successive layers of the basic building units, so that no swelling occurs, and the natural crystals consist of about 100 unit layers stacked one upon the other. The clay platelets are charged mainly due to the broken edge charges, which are sensitive to the pH of the suspension. The slurries are low viscosity because of the non-swelling structure of the clay. The origin of the clay is often hydro-thermal alteration of feldspars, or from volcanic ash, particularly under acid conditions Extensive deposits of pure clay are found in Georgia. US.A. and Cornwall. The characteristics of fine particle size, whiteness and low viscosity are exploited in various industries, such as paper making and ceramics. The clay is extensively found in shales and marine deposits. There is a tendency towards alteration to illite and chlorite at greater depth (age). Kaolin can be found in sandstone reservoirs in a diagenetic form, known as Dickite. 3.2.4.2 Micas（云母）

Fig.3-8 Diagrammatic sketch of structure of M uscovite

Micas are a 2:1 lattice type mineral, where two silica units sandwich an octahedrat layer, as shown in Figures 3-5 and 3-9. The two important features of micas are that the ion replacement is mainly in the tetrahedral layer, where silicon is replaced by aluminium or iron, and that the charge deficiency is balanced by potassium ions. In well crystallised micas, about one in four of the silicon atoms are replaced by aluminium. The role of potassium in the mica structure will be discussed in some detail because it is fundamental to an understanding of borehole stabilisation using potassium chloride brine. The main characteristics of a cation will be the number of charges they carry and the diameter of the ions. It will be seen that the smaller the sphere and the greater the number of charges, so the charge density will be higher.

39

A high charge density will, in turn, attract polar water molecules more strongly. Table 3-2 lists the diameters of common cations in the dehydrated and hydrated state. Table 3-2 Aton

Ionic radii of ions before and after hydration Dehydrated lon Diameter

Hydrated lon Diameter

A（埃）

A（埃）

Na-Sodium

1.90

5.5-11.2

K-Potassium

2.66

4.64-7.6

Cs-Cesium

3.34

4.6-7.2

M g-M agnesium

1.30

21.6

Ca-Calcium

1.90

19.0

A range is given because different techniques for measuring the ion diameter give rise to different values. It can be seen that the potassium ion has a small diameter and, as a consequence, can fit neatly into the hexagonal holes in the silica layer and very effectively neutralise the charge deficiency in that layer. Thus successive sheets are strongly bound together and a non-expanding structure is produced. Muscovite mica(白云母 ) is dioctahedral, i.e. only two thirds of the possible octahedral positions are occupied. The structural formula is (OH) 4 K2 (Si6 Al2 )Al4 O2 O, and the theoretical chemical composition is K2 O, 11.8%, SiO2 , 45%, Al2 O3 , 38.5%, H2 O, 4.5%. The biotite micas(黑 云母 ) are trioctahedral with the octahedral positions populated mostly by Mg2+, Fe2+ and/or Fe3+. It is important that in the well crystallised micas, no imperfections in the regularity of stacking occur. The mica used for lost circulation material is of this type. The illite（伊砾石） clay minerals differ from the well crystallised micas in several possible ways. The micas found in sedimentary shale sections would normally be classed as illite. There is less substitution of Al3+ for Si4+ and the net unbalance charge deficiency is reduced from 2 per unit cell to about 1.3 per unit cell. The potassium ions between the unit layers may be partially replaced by other cations, possibly Ca2+, Mg2+ or H+. Thus, the illite or mica may react with potassium ions and be stabilised to some extent. The smectites often degrade to micas or illites through reaction with potassium ions. Mica or illite concentrations tend to increase with age and depth.

40

Fig.3-9 Diagrammatic sketch of the structure of M ontmorillonite-Bentonite

3.2.4.3 Montmorillonite（蒙脱石） Montmorillonite is the major clay mineral in "bentonite(膨润土 )", or "fresh water gel", and is the most common mineral in a group of minerals called the smectites. A diagram of the structure is given in Figures 3-5 and 3-9. The essential feature that gives rise to the expandable structure is that the ionic substitutions are mainly in the octahedral layer. Thus, the charge is in the centre of the layer, so that the cations that are associated with the mineral to balance the ionic charge are unable to approach the negative charge sites close enough to completely lose the ionic character of the cation or the mineral surface. This residual ionic character provides the attractive force for the adsorption of polar molecules, such as water, between the unit sheets. The unique properties of montmorillonite are due to the very large surface area available when the clay expands and hydrates fully to just single sheets. Table 3-3 gives the surface areas for kaolin, illite and montmorillonite determined by adsorption of a non-polar molecule, nitrogen, and polar water molecules. It will be seen that only montmorillonite has the greater available area to the polar adsorbent. The full potential area is not available in these experiments, as the theoretical surface area of montmorillonite on dispersion to nearly unit cell dimensions, is 800 M2 /g. Table 3-3 Surface areas of clay samples determined by nitrogen and water vapour adsorption

41

S ample

Surface Area M2/g Nitrogen

Na Bentonite Kaokinite Illite

Water Area

Water +

Nitrogen Area ＊

38

203 /250

16

+

＊

12 /12

0.8

56

+

＊

0.9/1.5

52 /82

5.3/6.6

The swelling behaviour is most dependent on the type of cation in the exchangeable sites. This will be discussed in terms of sodium and calcium, since these are the most common soluble ions. A monovalent cation（单价阳离子） , such as sodium, can associate with a charge deficient area such that dispersion in water will create separated sheets. A divalent cation（二价阳离子）, such as calcium, cannot effectively associate with two negative charge centres on one sheet, and thus must bind two sheets together. Contact with water can cause swelling and mechanical dispersion may separate a sheet, but the ulimate surface area available, and the volume of closely associated water, will be considerably lower than with the sodium system. These different hydration patterns are illustrated in Figures 3-10 and 3-11.

Fig. 3-10 Hydration of Calcium M ontmorillonite

Fig. 3-11 Hydration of Sodium M ontmorillonite

Natural bentonite occurs as the calcium form. The deposit in Wyoming is fairly unique in that it is predominantly in the sodium form and thus hydrates and expands more fully. This clay is preferred as a drilling mud additive because the desired viscosity is obtained at low concentrations. The calcium clays are often chemically treated with sodium carbonate to partially convert them to the sodium form. Expandable montmorillonite can exist in substantial quantities in shales as the result of volcanic ash falling into a marine environment. The shales show the expected reaction to water in that the clay expands, and the high surface area gives a plastic, sticky cutting when being drilled. The clays are often termed "Gumbo" clays.

42

3.2.4.4 Sepiolite （海泡石）and Attapulgite（绿坡缕石）

Fig. 3-12 Schematic structure of Sepiolite and Attapulgite

The clay minerals, sepiolite and attapulgite, are used to viscosify salt water based drilling fluids and are similar in structure. A diagram of the structures is given in Figure 3-12. Attapulgite consists of double silica chains running parallel to the long axis, The chains form a network of strips which are joined together along the edges. The upper and lower parts of each chain are held together by aluminium, and/or magnesium, in octahedral coordination. The overall structure resembles a channelled wall where every second brick is missing. Diagrammatic representations of attapulgite and sepiolite are given in Figure3-12. In sepiolite the chains are formed from two silica chains to give wider channels. Attapulgite derives three unusual characteristics from its unique structure. First, because the structure consists of three-dimensional chains it cannot swell like clays such as montmorillonite which have a sheet structure. Second, there is a cleavage plane along the long axis, parallel to the silica chains, so that the mineral crystals have a needle-like shape, typically 1 micron long and 0.01 micron wide. Third, the mineral has a high sorbtive capacity for water, where some is held loosely onto the surface and some is bond strongly in the channels and is referred to as "zeolitic(沸 石 )" water. The clays have a large surface area and thus are effective viscosifying agents. Flocculation by salt water with subsequent reaggregation, will not occur with the needle shaped particles. The

43

needle shaped particles do not have the right shape to form an impermeable filter cake. Fluid loss control has to be achieved by the addition of other products and often small quantities of prehydrated bentonite are added. 3.2.4.5 Chlorite（绿泥石）

Fig.3-13 Diagrammatic sketch of the structure of Chlorite

The chlorite structure consists of alternate mica-type/brucite（氢氧镁石） -type layers, where the charge deficiencies in the mica layer are balanced by what is, in effect, a polymeric cation. The general structure is given in Figure 3-13. The bonding between layers is strong, and similar to that found in kaolinite, thus the clay is a low viscosity type. Chlorite tends to be associated with older sediments, so that kaolin and smectites tend to be replaced by chlorite and illites.

3.3 The Colloidal Che mistry of Clay Minerals(粘土胶体化学) 3.3.1 Ion Exchange(离子交换) As already mentioned, cations are adsorbed on the basal surfaces of clay crystals to compensate for atomic substitutions in crystal structure. Cations and anions are also held at the crystal edges, because the interruption of the crystal structure along the c axis results in broken valence bonds. In aqueous suspension, both sets of ions may exchange with ions in the bulk solution（基液）. The exchange reaction（交换反应） is governed primarily by the relative concentration of the different species of ions in each phase, as expressed by the law of mass action. For example, for two species of monovalent（单价） ions, the equation may be written: [A]c/[B]c=K[A]s /[B]s 44

Where [A] s and [B]s are the molecular concentrations of the two species of ions in the solution, and [A]c and [B]c are those on the clay. K is the ion exchange equilibrium constant（交换平衡常 数） , e.g., when K is greater than unity, A is preferentially adsorbed. When two ions of different valencies are present, the one with the higher valence is generally adsorbed preferentially. The order of preference usually is: H+> Ba++> Sr++> Ca++> Cs +> Rb+> K+> Na+> Li+, but this series does not strictly apply to all clay minerals: there may be variations. Note that hydrogen is strongly adsorbed, and therefore pH has a strong influence on the base exchange reaction. The total amount of cations adsorbed, expressed in milliequivalents per hundred grams of dry clay, is called the cation exchange capacity (CEC 阳离子交换容量). The CEC of a clay and the species of cations in the exchange positions are a good indication of the colloidal activity of the clay. A clay, such as montmorillonite that has a high cation exchange capacity, swells greatly and forms viscous suspensions at low concentrations of clay, particularly when sodium is in the exchange positions. In contrast, kaolinite is relatively inert, regardless of the species of exchange cations. The CEC and the species of exchange cations may be determined in laboratory by leaching the clay with excess of a suitable salt, such as ammonium acetate（醋酸铵）, which displaces both the adsorbed cations and those in the interstitial water. Then, another sample is leached with distilled water, which displaces only the ions in the interstitial water. Both filtrates are analyzed for the common exchange cations: the difference between the ionic content of the acetate and water leachates（沥出液） gives the meq of each species adsorbed on the clay, and the total meq of all species of cations gives the CEC. A field test for the approximate determination of the CEC (but not the species of cations) based on the adsorption of methylene blue is given in Chapter 2. 3.3.2 Clay Swelling Mechanisms（粘土膨胀机理）

Fig.3-14 Diagrammatic representation of a 3 layer expanding clay lattice

All classes of clay minerals adsorb water, but smecitites take up much larger volumes than do 45

other classes, because of their expanding lattice. For this reason, most of the studies on clay swelling have been made with smectites, particularly with montmorillonite. Two swelling mechanisms are recognized: crystalline and osmotic. Crystalline swelling（晶体 膨 胀 ） (sometimes called surface hydration- 表 面 水 化 ), results from the adsorption of mono-molecular layers of water on the basal surfaces-on both the external, and in the case of expanding latticed clays, the inter-layer surfaces (see Fig. 3-14).

The first layer of water is held

on the surface by hydrogen bonding to the hexagonal network of oxygen atoms, as shown in Fig.3-15. Consequently, the water molecules are also in hexagonal coordination. The next layer is similarly coordinated and bonded to the first, and so on with succeeding layers. The strength of the bonds decreases with distance from the surface, but structured water is believed to persist to distances of 75-100 A from an external surface. The structured nature of the water gives it quasi-crystalline properties. Thus, water within 10 A of the surface has a specific volume about 3% less than that of free water(compared with the specific volume of ice, which is 8% greater than that of free water.) The structured water also has a viscosity greater than that of free water. The exchangeable cations influence the crystalline water in

Fig.3-15 Crystalline swelling

two ways. First, many of the cations are themselves hydrated i.e., they have shells of water molecules (exceptions are NH4 +, K+ and Na+). Second, they bond to the crystal surface in competition with the water molecules, and thus tend to disrupt the water structure. Exceptions are Na+ and Li+, which are lightly bonded and tend to diffuse away. Osmotic swelling（渗透膨胀） occurs because the concentration of cations between the layers is greater than that in the bulk solution. Consequently, water is drawn between the layers, thereby increasing the c-spacing and permitting the development of the diffuse double layers that are discussed in the next section. Although no semi-permeable membrane is involved, the mechanism is essentially osmotic, because it is governed by a difference in electrolyte concentration. Osmotic swelling cause much larger increases in bulk volume than does crystalline swelling. For example, sodium montmorillonite adsorbs about 0.5 g water per g of dry clay, doubling the volume, in the crystalline swelling region, but about 10g water per g dry clay, increasing the volume twenty fold, in the osmotic region. On the other hand, the repulsive forces between the layers are much less in the osmotic region than in the crystalline region. 3.3.3 The Electrostatic Double Layer（扩散双电层） At the beginning of this chapter, we said that particles in colloidal suspension carried a surface charge. This charge attracts ions of the opposite sign, which are called counter ions（反离子）, and the combination is called electrostatic double layer（双电层） . Some counter ions are not tightly held to the surface and tend to drift away, forming a diffuse ionic atmosphere（扩散离子氛） around the particle. In addition to attracting ions of the opposite sign, the surface charge repels those of the same sign. The net result is a distribution of positive and negative ions, as shown schematically in Fig. 3-16. In the case of clays, the surface charge is negative, as we have seen, and the exchangeable cations act as counter ions. The distribution of ions in the double layer results in a potential grading from a maximum at the clay surface to zero in the bulk solution, as 46

shown in Fig. 3-17.

Fig.3-16 Diagrammatic representation of the electrical double layer

Fig. 3-17 Diagram illustrating the zeta potential

The layer of cations next to the surface of the particle, known as the Stern layer, is bound to and moves with the particle, whereas the diffuse ions are independently mobile. Thus, if a clay suspension is placed in a cataphoretic cell（阳离子电泳池）, the particle plus the Stern layer moves to the cathode（阴极）. The potential difference from the Stern layer to the bulk of the solution is known as the zeta potential（电动电位-ξ 电位） , and is a major factor controlling the behavior of the particle. The zeta potential is maximum, and the mobile layer（移动层） is most diffuse when the bulk

47

solution is pure water. Addition of electrolytes（ 电解液） to the suspension compresses the diffuse layer（扩散层）, and reduces the zeta potential. The zeta potential decreases greatly with increase in valence of the added cations, especially if low valence ions are replaced by high valence ones through base exchange, the ratio being approximately 1 to 10 to 500 for monovalent, divalent, and trivalent cations, respectively. The zeta potential is also reduced by the adsorption of certain long-chain organic cations. In some cases, it is possible to neutralize and reverse the zeta potential. The potential difference between the surface of the particle and the bulk solution is known as the Nernst potential（热力学电位）. This potential is constant, and independent of the electrolytes in solution. 3.3.4 Particles Association Clays play a significant role in drilling fluids, particularly the water based ones. They may be added intentionally to control the viscous flow properties and to provide the colloidal properties required for fluid loss control. In most cases there is a rapid build up in the circulating fluid of clays from the formation. The flow properties and fluid loss control are both modified by chemical treatment, either added intentionally or as a consequence of drilling through water soluble "formations", such as cement, anhydrite salt or magnesium salts. 3.3.4.1 Particle associations（粒子结合） The associations between clay particles are important as they affect important properties, such as viscosity, yield and fluid loss. The terms describing the associations are as follows:-Deflocculated(解絮凝). A system of suspended particles is described as deflocculated, or dispersed, when there is an overall repuls ive force between the particles. This is normally achieved by creating the conditions in which the particles carry the same charge. In clay systems, under alkaline conditions, this is normally a nett negative charge. Flocculated Systems(絮凝体系). A system may be described as flocculated when there are nett attractive forces for the particles and they can associate with each other, to form a loose structure. Aggregated Systems(聚结体系). The clays consist of a basic sheet structure and the crystals consist of assemblages of the sheets, one upon the other. In the swelling clay montmorillonite, the sheets can be separated from one another by hydration forces and by mechanical shear. Thus, a clay aggregate is an assemblage of sheets, that may be disaggregated by hydration and/or mechanical shear. Sheets, or the aggregates themselves, may be flocculated or deflocculated as shown in Figure 3-18.

48

Fig. 3-18 M odes of particle association of clays

Dispersed System(分散体系 ). A system in which the breakdown of the aggregates is complete is called a dispersed system. Both the dispersed clays and the aggregates themselves may be flocculated or deflocculated. The clays may be regarded as sheets assembled into books, with an "edge' surface and a "face" surface. The edge may carry charges arising from broken bonds, which may be positive or negative and are dependent on pH. The face may carry pH independent negative charges. The particle associations possible are given in Figure 13. 3.3.4.2 Interparticle forces（粒间力） The forces acting on the clay particles can be described as either repulsive forces or attractive forces. The particles approach each other due to Brownian motion. Whether they will agglomerate or not will depend on the summation of these two forces. 3.3.4.2.1 Repulsive forces(斥力) Electrical Double Layer Repulsion（双电层斥力）. The clay particles have been described as small crystals that have a negatively charged surface. A compensating charge is provided by the ions in solution that are electrostatically attracted to the surface. At the same time there is a need for the ions to diffuse away from the surface, towards the bulk of the solution. The action of the two competitive tendencies results in a high concentration of ions near the surface with a gradual fall off further from the surface. The volume around the clay surface is called the The "thickness" of the layer is reduced by the addition of salt or electrolyte. The reduction in

49

thickness is related to the salt concentration and to the valence of the ions of opposite charge. Thus, calcium chloride will compress the double layer more effectively than sodium chloride. When two particles, each with their diffuse counter-ion atmosphere, approach each other, there is an interference that leads to changes in the distribution of ions in the double layers of both particles. A change infers that energy must be put into the system to force the particles together. In other words, there will be a repulsion between the particles that will become larger the closer the particles approach each other.

Fig. 3-20 Diagram to illustrate the origins of the Van der Waals attractive forces Figure 3-19．Effect of salt on the attractive and repulsive force between clay particles

However, since the electric double layer can be compressed by electrolytes, then, as the electrolyte level is increased, so the particles can approach closer to each other before the repulsive energies are significant. This is shown in Figure 3-19. Born Repulsion(博恩斥力). This is a very short-term repulsion force that is generated when contact is close enough to distort the electrons in the atoms. It resists the interpenetration of the crystal lattices. Desorption of Water（水的解吸附作用）. The polar nature of the clay surface holds one or two layers of water tightly to the surface. Thus for the particles to approach closely to one another, energy has to be expanded to desorb the water. This repulsive energy probably becomes appreciable at particle separations of the order of 10 Angstroms or less. 3.3.4.2.2 Attractive forces（引力）

50

Van der Waals Forces（范德华力）. Van der Waals forces arise through the attraction of the spontaneous dipoles being set up due to distortion of the cloud of electrons around each atom. This is illustrated in Figure 3-20 (Van der Waals dipoles). For two atoms, the attractive force decays very rapidly with distance (I/d7 ), but for two spherical particles, the force is inversely proportional to only the third power of the distance (l/d3 ). Thus, for a large assemblage of atoms, such as in a clay platelet, this force can be significant as it is additive. The attractive force is essentially independent of the electrolyte concentration. 3.3.5 Flocculation and Deflocculation（絮凝与反絮凝） As mentioned in the beginning of this chapter, colloid particles remain indefinitely in suspension because of their extremely small size. Only if they agglomerate(聚结 ) to larger units do they have finite sedimentation rates. When suspended in pure water, they cannot agglomerate, because of interference between the highly diffuse double layers. But if an electrolyte(电解质) is added, the double layers are compressed(压缩), and if enough electrolytes are added, the particles can approach each other so closed that the attractive forces predominate, and the particles agglomerate. This phenomenon is known as flocculation(絮凝), and the critical concentration of electrolyte at which it occurs is known as the flocculation value(絮凝值 ). The flocculation value of clays may be readily determines by adding increasing amounts of electrolyte to a series of dilute suspensions. The change from a deflocculated suspension to a flocculated one is very marked. Before flocculation, the coarser particles may sediment out, but the supernatant fluid(上清液) always remains cloudy. Upon flocculation, clumps of particles big enough to be seen by the naked eye are formed; these sediment, leaving a clear supernatant liquid. The particles are very loosely associated in the flocs, which enclose large amounts of water(see Figure 3-21), and consequently form voluminous sediments.

Fig.3-21 Schematic representation of flocculated clay platelets

The flocculation value depends on the species of clay mineral, the exchange cations thereon, and on the kind of salt added. The higher the valence of the cations (either on the clay or in the salt), the lower the flocculation value is. Thus, sodium montmorillonite is flocculated by about 15 meq/l of sodium chloride, and calcium montmorillonite by about 0.2 meq/l of calcium chloride. The situation is more complicated when the cation of the salt is different from the cation on the clay, because then base exchange occurs, but the flocculation value is always much lower whenever polyvalent cations are involved. For instance, the flocculation value of sodium montmorillonite by calcium chloride is about 5 meq/l, and of calcium montmorillonite by sodium

51

chloride about 1.5 meq/l. +

There is a slight difference in the flocculating power of monovalent salts, as follows: Cs > + Rb > NH4 +> K+> Na+ Li+ This series is known as the Hoffmeister series, or as the lyotropic series(离子促变序列). If the concentration of clay in a suspension is high enough, flocculation will cause the formation of a continuous gel structure() instead of individual flocs. The gels commonly observed in aqueous drilling fluids are the results of flocculation by soluble salts, which are always present in sufficient concentrations to cause at least a mild degree of flocculation. Flocculation may be prevented, or reversed, by the addition of the sodium salts of certain complex anions, notably polyphosphates( 多 磷 酸 盐 ), tannates( 丹 宁 酸 盐 ), and lignosulfonates(磺化褐煤). For instance, if about 0.5% of sodium hexameta-phosphate(六偏磷 酸钠) is added to a dilute suspension of sodium montmorillonite, the flocculation value is raised from 15 meq/l to about 400 meq/l of sodium chloride. A similar amount of a polyphosphate will liquefy a thick gelatinous mud. This action is known as peptization（ 胶 溶 作 用 ） or deflocculation（反絮凝作用）, and the relevant salts are called deflocculants of thinners in the drilling mud business. There is little doubt that thinners（稀释剂） are adsorbed at the crystal edges. The small amounts involved are comparable to the anion exchange capacity, and there is no increase in the c-spacing, such as one would expect if they were adsorbed on the basal surface. The mechanism is almost certainly chemisorption（化学吸附）, because all the common thinners are known to form insoluble salt, or complexes，（络合物, 螯合物） , with the metals such as aluminum, magnesium, and iron, whose atoms are likely to be exposed at the crystal edges. 3.3.5.1 Deflocculation mechanisms（解絮凝机理） To maintain a system in a deflocculated state the repulsive forces must be maximised. This can be achieved by two mechanisms. Low Salt Concentrations（低浓度盐）. In order to maximise the electrostatic repulsion, the electrolyte concentration has to be as low as possible. Figure 15 shows how the repulsive forces predominate at low salinities. Maximum Negative Charge(最大负电荷). The conditions have to be chosen so that the negative charges on the clay particles are at a maximum. This can be done in two ways:— A.

B.

High pH conditions: A pH of above 8.0 will increase the number of negative silicic acid groups on the clay edges. Thus, maintenance of alkaline pH conditions with caustic soda will stabilise the clay system. Addition of deflocculants or dispersants: There is a wide range of chemicals known as dispersants or thinners that have a wide range of chemical structure. However, they can all be described as negatively charged polymers. Figure 3-22 illustrates the mechanism whereby a short chain, negatively charged polymer can neutralise a positive charge on the edge to become adsorbed.

52

Fig. 3-22 Diagram to illustrate low M .W. polymers acting as deflocculant and high M .W. polymers acting as flocculants

Then, the other negative groups increase the negative charge density on the clay platelet, Some of the more common chemicals are listed in Table 3-4. Table 3-4 Drilling Fluid Thinners pH of 1%

Chemical 1.Sodium

acid

4.3

pyrophosphate(sapp) 2. Sodium tetraphosphate

Decomposes and forms flocculating agent above 175 ℉ . Not effective in the presence of large quantities of calcium.

8.0

Same as 1.

7.0

M aterial starts to decompose at temperatures above 300℉. pH

3. Chrome Lignosulfonate

4. Lignite

Limitations

S olution

needs to be at least 9.0. 3.2

M aterial starts to decompose at temperatures above 350℉. pH needs to be least 9.0.

5. Tannin

5.0

Not very effective if pH of mud is less than 11.0

—

M any types, temperature stability above 300℉ may be a problem.

6. Surfactants

M ost are more expensive than other materials. 7.5

7. Low Viscosity CM C

Decomposes at temperature above 250 ℉ . Sensitive to high calcium. Used in salt water drilling fluid system for deflocculant fluid loss control.

Since the deflocculants are reacting with the positive sites on the edges, and the edge surface area is relatively a small proportion of the total, the chemicals can be effective at low dose rates. Also 53

note that the materials tend to be acidic. Thus, caustic soda additions should also be made with the thinner. The other fine particulate solids, such as sand, calcium carbonate or barites, will react in essentially the same way. 3.3.5.2 Flocculation mechanisms（絮凝机理） There are a number of mechanisms by which the interparticle attractive forces can be increased and repulsive forces decreased. In many drilling fluid systems the clays are deflocculated and the change to a flocculated condition can drastically alter the fluid properties. These mechanisms often occur while drilling a well. High Salt Concentrations(高浓度盐). Figure 3-18 shows how the higher salt levels, by contracting the Gouy layer, allows the particles to approach each other close enough for the shorter range attractive forces to predominate. The upper limit of salinity, for bentonite to yield satisfactorily, is about 2%, sodium chloride. In drilling practice this reaction occurs when a fresh water clay based fluid is used to drill into a salt section, or when a fresh-water system has salt added to it in preparation to drill evaporite sequences. Polyvalent Cations（多价阳离子）. A soluble cation containing more than one positive charge can react with more than one exchange site on the surfaces of more than one clay platelet, to form an "ion bridge" between the clays to produce a flocculated structure as shown in Figure 3-23. Calc ium is the most common ion, although aluminium, magnesium and zirconium are other examples. Calc ium is often encountered in the form of gypsum (calcium sulphate) and cement. If the clays in the drilling fluid are in the sodium form, then the contac t with calcium will drastically alter the properties. Some mud systems overcome this problem by ensuring that the clays are already in the calcium form before the contaminant is encountered. Thus, lime or gypsum is added in excess to ensure a source of calcium is available. The aluminium and zirconium ions have been suggested as treatments for production sands to flocculate the clay minerals and thus prevent their mobilisation to block the pores of the production zone. The flocculation is followed by aggregation of the clays as shown in Figure 18.

54

Fig. 3-23 Diagram to show the initial flocculating effect of calcium as polyvalent ion bridge is formed between clay particles. This is followed by ion exchange reactions to form the aggregated calcium clay

Addition of Polymeric Flocculants(加入聚合物絮凝剂). These polymers extend the concept of an "ion bridge" of the polyvalent cations, to a polymer bridge between clay platelets. This is illustrated in Figure 3-22. The main feature of the flocculants is a very high molecular weight, so that the molecule spans the distance between particles. The molecules must also adsorb onto the particles, so the presence of anionic or cationic groups often makes the molecules more effective. There are two cases where the polymeric flocculants are used One is in "clear water" drilling, where the drilled solids are removed by the flocculant in order to keep the density low. The other is where the polymer is added to stabilise a hydratable formation. Low pH conditions（低 pH 值）. Since the edge charges are pH dependent, a low pH will generate more positive sites and encourage face to edge association. Values of pH below 7, and no caustic soda treatment, would probably induce this reaction. Acid may be added to flocculate drilled solids in a sump clean up operation. 3.3.6 Aggregation and Dispersion（聚结与分散） Although all forms of particle association are termed flocculation in classical colloid chemistry, in drilling fluid technology it is necessary to distinguish between two forms of association, because they have a profoundly different effect on the rheology of suspensions. The term flocculation is limited to the loose association of clay platelets which forms flocs or gel structures, as discussed in the preceding section. The term aggregation（聚结） , as used here, refers to the collapse of the diffuse double layers and the formation of aggregates of parallel platelets spaced 20 A or less, apart. Aggregation is the reverse of the sudden increase in c-spacing that Norrish observed when the layers in a flake of sodium montmorillonite overcame the attractive forces between them, and expanded to virtually individual units. Thus, whereas flocculation causes an increase in gel strength, aggregation causes a decrease because it reduces (1) the number of units available to build gel structures and (2) the surface area available for particle interaction. The term dispersion（分散） is commonly used to describe the subdivision of particle aggregates in a suspension, usually by mechanical means（机械方法）. Garrison proposed extending the term to the subdivision of clay platelet stacks, which is usually the result of electro-chemical effects （ 电 - 化 学 作 用 ） , and thus to distinguish between the

55

dispersion-aggregation process and the deflocculation-flocculation process. The difference between the two processes (the flocculation-deflocculation process on the one hand, and the aggregation-dispersion process on the other) is illustrated schematically in Fig. 3-24. The two left hand pictures show 1% suspensions of calcium bentonite and of sodium bentonite in distilled water. The calcium bentonite is aggregated and the sodium is dispersed, but both are deflocculated, as shown by the misty supernatant liquid after centrifuging. The picture on the lower right shows that calcium bentonite suspension after the addition of 0.01N calcium chloride; the upper right-hand picture shows the sodium suspension after the addition of 0.1N sodium chloride. Both are flocculated, as shown by the clear supernatant, but the calcium bentonite suspension is aggregated and the sodium bentonite suspension is dispersed, as shown by the much greater volume sediment.

Fig.3-24 Schematic representation of the flocculation-deflocculation mechanism and the aggregation-diespersion mechanism

3.3.7 Viscosity control（粘度控制） One of the most important functions of a drilling fluid is to remove the cuttings from the bit and transport them to the surface. The efficiency of this process will depend mainly on the circulation rate and the theological properties of the fluid. Clay minerals will play a significant role because they will inevitably be present as the colloidal solids in the fluid, as a result of breakdown of the formation. Also, clays, such as montmorillonite(in the form of bentonite), attapulgite or sepiolite, may be specifically added for viscosity control. The viscous or flow properties of the fluid have to be designed carefully and maintained to reasonably close tolerances. These properties can be measured and defined mathematically. The mathematical treatment will be discussed elsewhere in this manual. The viscosity, or resistance to flow, is the result of interactions between the continuous phase of water or oil and solids or dissolved high molecular weight polymers. These interactions take the form of weak chemical bonds or ionic interactions that can be broken by shear or mechanical forces. This gives rise to the important property described as "shear thinning" or "thixotropic"

56

behaviour. Thus, under low shear conditions, such as exist when the fluid is not being pumped or in the annulus, the maximum viscosity is developed that will suspend or carry the cuttings more effectively. A thixotropic fluid will also possess the low viscosities required at the bit where the fluid has to "search" for microfissures and cracks. Another important function of the fluid is to suspend particles when it is not being circulated. A behaviour described as "gellation" indicates that there are also time dependent forces at work within the fluid. This means that the attractive forces disrupted by shear may take some time to rearrange. This section will discuss the types of physiochemical forces that can exist between suspended solids and water soluble polymers and how they can be modified. 3.4 Interactions of Components in Drilling Fluids(钻井液中各种组分之间的作用) 3.4.1 Clay-Water Interactions（水-土相互作用） The surfaces of the clays contain hydroxyl and oxygen groups which form hydrogen bonds to water molecules. The exchangeable cations adsorbed on the clay surface will also have an envelope of closely associated water molecules. Also, water will form a bond with negative sites on the edges. These interactions combine to create a zone of 10-15 layers of water closely associated with the clay, creating a "hydration envelope". In the case of sodium montmorillonite, this envelope may extend 60A, or about 20 layers of water. Thus, the introduction of clays into water reduces the volume of "free'" water, builds "structure" and resistance to shear. 3.4.2 Polymer.-Water Interactions（聚合物-土相互作用） In a similar manner to clays, the water soluble high molecular weight polymers create a sheath of closely associated water around each molecule. 3.4.3 Clay-Clay Interactions（土-土相互作用） The interactions between clay particles have already been described in terms of whether there is a nett attraction or repulsion between the particles in states described as flocculation or deflocculation respectively. The factors influencing the level of interaction were described in some detail. As expected, the factors increasing particle interactions tend to increase the viscosity. Careful balance of the state of flocculation and deflocculation will give the optimum flow properties and fluid loss control. 3.4.4 Clay- Polymer Interactions（土-聚合物相互作用） The reactions between clays and polymers will depend on a number of factors. Molecular Weight（分子量）. There will be a direct relationship between the molecular weight and the length of the molecule. A high molecular weight material, such as a synthetic polyacrylate with a molecular weight of 107, will have a chain length approximately 20 microns, which may be very much larger than the clay particles. Thus, it is possible for one molecule to adsorb onto more than one particle of clay and form an association of the clay particles. Thus, high molecular weight polymers will act as flocculants. Low weight polymers can alter the charge on individual clay particles so that they may be equally charged and deflocculated. Adsorption onto the Clay（在粘土上的吸附）. The strength the adsorption and the site of adsorption will depend on the chemical character of the polymer. Generally, negatively charged polymers can adsorb on cationic sites generated on the edges. Most polymers used in drilling 57

fluids tend to be of this type. Adsorption tends to be stronger for higher molecular weight materials. Other factors, such as charge density, salinity, pH, etc., make the situation too complex to generalise. Polymers can be used to provide very precise control of flow properties. Another feature is that the flow properties can be significantly altered with only very small additions of polymer, often less than 0.5%. 3.4.5 Polymer-Polymer Interactions（聚合物-聚合物相互作用） In addition to polymer reactions with clays, there will also be interactions with themselves through a tangling mechanism, which will be most pronounced for the longer chains. Thus, the higher molecular weight polymers will give higher viscosities on an equal concentration basis than lower molecular weight or shorter polymers. The factors influencing viscosity are summaried in Table 3-5. Table 3-5 Factors Influencing Viscosity To Increase Viscosity 1. Increase level of solids. 2. Add high molecular weight viscosifying polymer. 3. Flocculate with calcium or other polyvalent cation. 4. Flocculate with salts. 5. Flocculate with low pH conditions. To Decrease Viscosity 1. Dilute with water. 2. Disperse with low molecular weight polymers. 3. Remove calcium by chemical treatment. 4. Disperse with higher pH conditions.

Exercises 1.

What are the two basic structure units of clay minerals?

2.

List the common clay minerals related to drilling operation and their crystalline structures and chemical compositions. What is isomorphous substitutions? Give the reasons that clay colloids carry charge deficiency and the different charges between the basal surface and the edge of clay minerals.

3. 4.

5.

6.

What is exchangeable cations and what is cation exchange capacity of clay minerals? How

does the cation exchange capacity affect the hydration performances of clay minerals, the properties of drilling fluids and the hole stability? The average charge deficiency of illite is higher than that of montmorillonite (0.69 vs 0.41), however, the cation exchange capacity is lower than of montmorillonite (10-40 vs 70-130 Meq/100g), explain the reasons for that. Based on the balancing cation in illite, potassium, give the reasons that potassium is used as an effective inhibitive agent.

7.

What is the mechanism of clay hydration? What are the hydration characteristics of

8.

montmorillonite, ellite and kaolinite? What is diffuse electric double layer and what is zeta potential (ξ )? Ho w doesξ affect the performances of clay colloids? What are the reasons that affect the zeta potential (ξ )?

58

CHAPTER 4

RHEOLOGY AND HYDRAULICS OF DRILLING FLUIDS

The flow properties of the drilling fluid play a vital role in the success of the drilling operation. These properties are primarily responsible for removal of the drill cuttings, but influence drilling progress in many other ways. Unsatisfactory performance can lead to such serious problems as bridging the hole, filling the bottom of the hole with drill cuttings, reduced penetration rate, hole enlargement, stuck pipe, loss of circulation, and even a blowout. The flow behavior of fluids is governed by flow regimes, the relationships, between pressure and velocity.

4.1 Rheology(流变学) The science of rheology is the study of the deformation of all types of matter. The rheologist is interested primarily in the relationship between flow rate(流速 ) and flow pressure(流动压力 ) and the influence thereon of fluid flow characteristics. There are two fundamentally different relationships between flow rate and pressure: A.

The laminar flow regime( 层 流 ) prevails at low velocities. Flo w is orderly and the pressure/velocity relationship is a function of the viscous properties of the fluid.

B.

The turbulent flow regime(紊流 ) prevails at high velocities. Flow is disorderly and governed by the inertial properties of the fluid in motion. Flo w equations tend to be empirical due to the complexity of the flow. As shown in Fig.4-1, pressure increases with velocity increase much more rap idly when flow is

turbulent than when it is laminar.

Fig.4-1 The relationship between Pressure and Velocity on the flow regime

4.1.1 Determinati on of Flow Regime（流态确定） The critical velocity for the onset of turbulence decreases with increase in p ipe diameter, with increase in density, and with decrease in viscosity, and is expressed by a dimensionles s number known as Reynolds number(雷诺数 ). With most drilling muds the critical value of the Reynolds number lies between 2000 and 3000.

59

N Re 

DV

4-1



The pressure loss of a fluid in turbulent flow through a given length of pipe depends on inertial factors, and is little influenced by the viscosity of the fluid. The pressure loss increases with the square of the velocity, with the density, and with a dimensionless number known as the Fanning friction factor(范宁摩擦系数 ), wh ich is a function of the Reynolds number and the roughness of the pipe wall.

f 

gDP 2V 2 L

4-2

4.1.2 Laminar Flow(层流)

Laminar Flow of Newtonian Fluids（牛顿流体层流） . Laminar flow is easiest understood by imagining a deck of cards resting on a plane surface. If a force, F, is applied to the end of the top card (see Fig. 4-2), and if, because of friction, the velocity of each successive lower card decreases by a constant amount, dv, from v to zero, then

F dv     A dr

4-3

where A is the area of the face of a card, r the thickness of the deck, dv the difference in velocity between adjoining cards, and dr the distance between them. μ is the frictional resistance（摩擦阻

力） to movement between the cards, or, in rheological terms, the viscosity（粘度）.  is the shear stress（剪切应力） , dv/dr is the shear rate（剪切速率） , expressed by  , or velocity gradient （速度梯度） , defined by the slope of the velocity profile.

Fig. 4-2 The relationship between shear stress/shear rate

Laminar flow in a round pipe may be visualized as infinitely thin cylinders sliding over each other (Fig.4-3a). The velocity of the cylinders increases from zero at the pipe wall to a maximum at the axis of the pipe, resulting in a parabolic velocity profile (Fig.4-3b). The difference in velocity between any two such cylinders, divided by the distance between them, defines the shear rate. The axial force divided by the surface area of a cylinder defines the shear stress. The ratio of shear stress to shear rate is called the viscosity, and is a measure of the resistance to flow of the fluid. The unit of viscosity is the poise; the shear stress in dynes/cm2 divided by the shear rate in reciprocal(倒数) seconds gives the viscosity in poises. The unit employed in mud viscometry( 粘 60

度测量 ) is the centipoises(cp), which is one hundredth of a poise.

(a)

(b) Fig. 4-3

(a) Schematic representation of laminar flow of a Newtonian fluid in round pipe, fluid velocity decreases from 0 at the wall to a maximum at the axis of the pipe; (b) Velocity profile of the fluid, the shear rate at any point is the slope of the profile at that point.

4.2 Rheological Models(流变模式) Frictional pressure loss is an extremely important part of drilling hydraulics analysis, since large viscous forces must be overcome to move drilling fluid through the longer, slender pipes and annuli used in the drilling process. A rheological model is a mathematical model used to describe the relationships between the viscous forces present in the fluid. A rheological model also describes the flow behavior of a fluid by expressing the relationship between the shear rate and the shear stress. Various models are proposed to describe the behavior of several ideal non-Newtonian fluids. The following five common rheological models are discussed: A. B. C. D.

Newtonian Bingham plastic Power Law Casson

E.

Herschel-Buckley

4.2.1 Newtonian Model (牛顿模式)

The viscous forces present in a simple Newtonian fluid are characterized by the fluid viscosity. Examples of Newtonian fluids are water, gases, and high-gravity oils. The Newtonian model is defined by the following relationship:



 

4-4

where τ = shear stress μ = Newtonian viscosity γ = shear rate In field (English) units, the viscosity is expressed in poises (1 poise = 1 g/cm/s). In the drilling industry, the viscosity is generally expressed in terms of centipoises (cp), where 1 cp = 0.01 poise. A plot of shear stress versus shear rate is known as a consistency curve（粘度曲线） . With fluids that contain no particles larger than a molecule (e.g., water, fuel oil, glycerine, gasoline), the consistency curve is a straight line passing through the origin, at a constant temperature and

61

pressure, the shear rate and the shear stress are directly proportional. The constant of proportionality (μ) is the Newtonian viscosity(牛顿粘度). The rheological curve(流变曲线) for a Newtonian fluid is a straight line that passes through the origin (see Figure 4-4). The slope of the line is the Newtonian viscosity. Since μ does not change with rate of shear, it is the only parameter needed to characterize the flow properties of a Newtonian liquid.

Fig.4-4 Rheological flow curve for a Newtonian fluid

4.2.2 Non-Newtonian fl ui ds（非牛顿流体）

Suspension such as drilling muds that contain particles larger than molecules in significant quantities does not conform to Newton's laws, and thus are classified under the general title of non-Newtonian fluids. The shear stress/shear rate relationship of non-Newtonian fluids depends on the composition of the fluid. 4.2.2.1 Bingham Plastic Fluids（宾汉塑性流体） Plastic fluids were first recognized by Bingham, and are therefore referred to as Bingham plastics（宾汉塑性流体） , or Bingham bodies. Clay muds having a high solids content behave approximately in accordance with the Bingham theory of plastic flow, which postulates that a finite stress must be applied to initiate flow, and that at greater stresses the flow will be Newtonian. The consistency curve of a Bingham plastic must therefore be described by two parameters, the yield point（屈服值） and the plastic viscosity, as shown in Figure 4-5, the equation for which is

   0   P

dv dr

4-5

Fig.4-5 Consistency curve of an ideal Bingham plastic

62

Where

 0 is the stress required to initiate flow, and  p is the plastic viscosity（塑性粘度）,

which is defined as the shear stress in excess of the yield stress that will induce unit rate of shear. Thus

p 

  0 

4-6

The total resistance to shear of a Bingham plastic may be expressed in terms of an effective （有 效） or apparent viscosity（表观粘度） . Effective viscosity is defined as the viscosity of a Newtonian fluid that exhibits the same shear stress at the same rate of shear. Figure 4-5 shows that effective viscosity at shear rate

 e1 

 1 is given by

1  0  0    p  0 1 1 1

Fig.4-7a

4-7

Thus effective viscosity may be considered as comprising two components: plastic viscosity, which corresponds to the viscosity of a Newtonian fluid, and structure viscosity(( 结构粘度 ), which represents the resistance to shear caused by the tendency for the particles to build a structure. As shown in Figure 4-5,

 0 /  forms a decreasing proportion of the total resistance to

shear as the shear rate increases, so that the effective viscosity decreases with increase in shear rate. Note particularly that the value of effective viscosity is meaningless unless the rate of shear at which it is measured is specified. Effective viscosity is a very useful parameter in many hydraulic equations when the shear rate is known, as will be discussed later. Plastic flow, as shown in Fig. 4-5, is never observed in practice: at pressure below the yield point, a slow creep is observed, as shown in Fig. 4-6. By examining the flow of suspension in a glass capillary under a microscope, Green showed that no shearing action was involved in this type of flow. The suspension flowed as a solid plug lubricated by a thin film of liquid at the capillary wall, the particles being held together by attractive forces between them. However lower the pressure, there was always some flow, although it might be as low as one cubic centimeter in one hundred years. He therefore concluded that there was no absolute yield point, and re-defined the Bingham yield point as the shear stress required to initiate laminar flow in the suspension.

Fig.4-6 Observed consistency curve of a Bingham plastic

63

(a) (b) Fig. 4-7 (a) Plug flow of a Bingham plastic in round pipe. RP/2L<τ0 (b) M ixed flow of a Bingham plastic in round pipe. RP/2L>τ0,rP/2L=τ0

Green showed that the flow of a Bingham p lastic in a round pipe is as follows: If the pressure is gradually increased from zero, the suspension at first flows as a plug (as described above) and the velocity profile is a straight line normal to the axis of the pipe (Figure 4-7a). Since shear stress is equal to

rP / 2 L , laminar flow starts at the wall of the pipe when

RP0 0 2L

4-8

where P0 is the pressure required to initiate plastic flo w. At pressures greater than Po, laminar flow progresses towards the axis of the pipe, so that flow consists of a plug in the center of the pipe surrounded by a zone of laminar flo w, and the velocity profile is as shown in Figure 4-7b.

4.2.2.2 Pseudoplastic Fluids（假塑性流体） Pseudoplastic fluids have no yield point; their consisitency curves pass through the origin. The curves are nonlinear, but approach linearity at high shear rates. Thus, if stress readings taken at high shear rates are extrapolated back to the axis, there appears to be a yield point similar to that of a Bingham plastic; hence the name pseudoplastic (Fig. 4-8). Suspensions of long-chain polymers are typical pseudoplastics. At rest, the chains are randomly entangles, but they do not set up a structure because the Fig. 4-8 The consistency curve for a

electrostatic forces are predominately repulsive. When Pseudoplastic fluid the fluid is in motion, the chains tend to align themselves parallel to the direction of flow; this tendency increases with increase in shear rate, so that the effective viscosity decreases. The consistency curve of the pseudoplastic flow model is described by an empirical equation, known as the power law:

  K(

dv n )  Kn dr

4-9

where K and n are constants which characterize the flow behavior of the fluid. K is the consistency index（稠度系数） , which corresponds to the viscosity of a Newtonian fluid, but is usually expressed in dynes/cm2 . n, the flow behavior index（流性指数）, indicates the degree of departure from Newtonian behavior. Actually, the power law describes three flow models, depending on the value of n:

64

A.

Pseudoplastic, n<1, the effective viscosity decrease with shear rate.

B. Newtonian, n=1, the viscosity does not change with shear rate. C. Dilatant（膨胀型流体）, n>1, the effective viscosity increases with shear rate. Since Equation 4-9 may be written

l o g  l o gK  n( l o g )

4-10

a logarithmic plot of shear stress versus shear rate is linear for a pseudoplastic fluid. As shown in Fig.4-9, the slope of the curve defines n, and the intercept on the stress axis at   1 defines K (since log 1=0). K and n may either be measured directly from the plot or calculated from two values of stress, as follows:

log  1  log  2 log  1  log  2

4-11

log K  log  1  n log  1

4-12

n

Fig. 4-9 Logarithmic plot of consistency curve of an ideal power law fluid

Fig.4-10 Determination of n and k in a direct indicating viscometer

or K 

1  1n

4-13

For example, if dial readings are taken at 600 and 300 rpm in direct-indicating viscometer, then

n

log  600  log  300 log 1022  log 511  3.32 log

4-14

 600  300

log K  log  600  3.0094 n

65

or K 

 600 (1022 )

n

lb / 100 ft 2

4-15

A graphical interpretation is given in Fig.4-10. The effective viscosity of a power law fluid is given by

e 

 gK ( )n   gK ( )n 1  

when K is dynes/cm2,

4-16

 is reciprocal seconds, e is in poises.

For the special case of Newtonian fluids, the slope of the consistency curves on a logarithmic plot is always 45o , since n = 1. If the stress is plotted in absolute units, the intercept on the stress axis at   1 gives the viscosity in poises. Although the Power Law more accurately represents the behavior of drilling mud at low shear rates, it does not have a yield stress; therefore, the Power Law can provide inaccurate results at very low shear rates. Most drilling muds exhibit behavior intermediate between ideal Bingham plastics and ideal power law fluids. Due to interparticle forces, n and K are not constant at low rates of shear. Muds have a rather indefinite yield point which is less than would be predicted by extrapolation of shear stresses measured at high shear rates. Figure 4-11 compares the consistency curves of the three flow models.

Fig.4-11 Ideal consistency curves for common flow models

The fact that the consistency curve of clay muds intercepts the stress axis at a value greater than zero indicates the development of a gel structure（凝胶结构）. This structure results from the tendency of the clay platelets to align themselves so as to bring their positively charged edges towards their negatively charged basal surfaces. This interaction between the charges on the platelets also increases the effective viscosity at low rates of shear, thereby influencing the value

66

of n and K. The gel strength（凝胶强度） of some muds, notably fresh water clay muds（淡水泥浆）, increases with time after agitation（搅拌） has ceased, a phenomenon that is known as thixotropy （触变性） . Furthermore, if after standing quiescent the mud is subjected to a constant rate of shear, its viscosity decreases with time as its gel structure is broken up, until an equilibrium viscosity is reached. Thus the effective viscosity of a thixotropic mud is time-dependent as well as shear-dependent. Pseudoplastic fluids have no yield point; their consisitency curves pass through the origin. The curves are nonlinear, but approach linearity at high shear rates. Thus, if stress readings taken at high shear rates are extrapolated（外推） back to the axis, there appears to be a yield point similar to that of a Bingham plastic; hence the name pseudoplastic. Suspensions of long-chain polymers are typical pseudoplastics. At rest, the chains are randomly entangles, but they do not set up a structure because the electrostatic forces are predominately repuls ive. When the fluid is in motion, the chains tend to align（排列） themselves parallel to the direction of flow; this tendency increases with increase in shear rate, so that the effective visc osity decreases. In general, a drilling fluid has both a yield stress and shear-thinning behavior. At high shear rates, all of the models represent the fluid behavior reasonably well. A typical drilling fluid tends to behave somewhere between the Power Law behavior and a Bingham fluid. There are other models used for modeling drilling fluids, such as the Casson model, the Robertson-Stiff model, and the Herschel-Bulkley model. Of these three, only the Herschel-Buckley and Casson models are described in detail in the remainder of this section. 4.2.2.3 Casson Model（卡森模式） The Casson model is a hybrid between the Bingham and Power Law model and allows for both yield behavior and shear-thinning within the framework of a two-parameter model. It allows confident extrapolation to high shear rates. This model is defined by

 1 / 2  k01 / 2  k11 / 2 1 / 2 The constants k 0 and k 1 can be evaluated from experimental data by the least-squares fit to the square roots of the shear stress and shear rate values. The effective Casson yield stress（有效卡森 动切力） is k 0 and the effective Casson high shear rate viscosity（有效卡森高剪粘度） (or Casson plastic viscosity) is k 1. The user may desire to interpret the Casson parameters or convert the parameters from one system to another. The Casson parameters are related to the Bingham parameters by the following relationships. The existing constants γ1 = 511s-1, and γ2 = 1022s-1 are used, which are the shear rates corresponding to the 300 and 600 rpm Fann readings. The Casson yield stress（卡森屈服应力） is τc and the viscosity is k c. The Bingham yield stress（宾汉屈服应力） is τb and the viscosity is μp . There is an intermediate calculation made before displaying the Bingham values. Two variables (τ1 , τ2 ) are defined as follows:



 1   c  kc 1



2

and

67



 2   c  kc 2



2

Rearranging gives the following:

p 

 2  1 2  1

and

b 

 2 1   1 2  2  1

Fig. 4-12 Casson fluid intercept as a function of the shear stress

From these two values, the correspondence between the Casson and Bingham model parameters is evident. At the wells ite, the choice of an accurate model is best accomplished by graphing the viscometer data from the mud engineer. These data typically consist of three quantities: the 300 and 600 rpm readings and the gel strength. The position of the gel strength along the shear stress axis predominantly determines which model is the best to use. If the gel strength is high and near the yield point, the fluid is best approximated by the Bingham model. If the gel strength is very low, the fluid is better approximated by the Power Law model. If six or more Fann readings are available, the Herschel-Bulkley model (next model covered) is best, unless the yield stress is very low (close to zero). In these cases, the non-linear least-squares fit of a Herschel-Bulkley model may produce a negative yield stress. The Casson model intercepts the shear stress axis at some point between the origin and the yield point that depends upon the ratio of the yield point to the plastic viscosity (see Figure 4-12). The intercept on the shear stress axis is given as a percentage of the yield stress. By comparing the gel strength to the intercept point, one may determine the accuracy of using the Casson model. For a two-parameter model, the Casson model provides a much better agreement than the Bingham model for Fluid, and provides a fair representation of the low shear rate behavior of the fluid. 4.2.2.4 Herschel-Bulkley Model（赫谢尔-巴尔克莱模式） The Herschel-Bulkley model is probably the most complete model currently in use. This model is also sometimes referred to as yield-pseudoplastic（带动切力的幂律模式） because it

68

encompasses both yield behavior of a non-Newtonian fluid and also allows for shear-thinning. The equation for a Herschel-Bulkley fluid is as follows:

   HB  K HB m where, τHB = the Herschel-Bulkley yield point（赫谢尔-巴尔克莱屈服值） KHB = the Herschel-Bulkley consistency factor（赫谢尔 -巴尔克莱） m = the Herschel-Bulkley flow behavior index（赫谢尔 -巴尔克莱流行指数） Due to the complexity of this model, analytical solutions are not readily available for pressure drop models. Furthermore, since there are three coefficients in the rheological model, at least three Fann readings are necessary to define the model. 4.3 Measurement of Rheological Properties（流变特性的测量） The measurement of fluid flow properties may be accomplished with a range of viscometric instruments, such as the following: A. Pipe flow rheometer B. Marsh funnel C. Rotating viscometer The pipe flow rheometer is primarily a laboratory tool and is not easy to use in the field. Using this tool, pressure drop is measured for a given length of pipe at selected flow rates. By the additional use of heat exchangers, the pressure drop measurements can be obtained at any pressure and temperature permitted. Marsh Funnel（马氏漏斗）and Rotating Sleeve/Bob Viscometer(See Chapter 2). 4.4 Pressure Drop Modeling（压降模型） 4.4.1 Introduction to Pressure Drop Modeling

Flow conditions in drillpipe（钻杆） are usually turbulent and are, therefore, only influenced by the viscous properties of the mud to a minor extent. The effective shear rate at the pipe wall is generally between 200 and 1,000 reciprocal seconds. The conduit dimensions are typically known quite accurately, so pressure losses are also determined quite accurately. The only uncertainties involved are the tool joint losses and the roughness of the pipe walls. The pressure loss in the drillpipe is about 20 to 45% of the pressure loss over the entire circuit (the standpipe pressure). Flow velocity through the bit nozzles（钻头喷嘴） is extremely high, corresponding to shear rates of 100000 reciprocal seconds. The pressure loss across the nozzles can be calculated accurately because it depends upon the coefficient of discharge, which is essentially independent of the viscous properties of the mud. The pressure loss across the bit nozzles is typically about 50 to 75% of the standpipe pressure. Flow in the annulus（环空） is usually laminar and is, therefore, a property of the viscous properties of the mud. Shear rates are generally between 50 and 150 reciprocal seconds. The pressure loss from the bit to the surface comprises only about 10% of the standpipe pressure in a conventional hole geometry (it is higher in slim holes). However, knowledge of the pressure and flow in the various sections of the annulus is very important when dealing with such problems as 69

hole cleaning, induced fracturing, and hole erosion. Unfortunately, accurate prediction of the flow relationships is usually difficult because of the numerous unknowns and uncertainties. Perhaps the greatest of the unknowns is the true diameter of the hole, which may be as much as twice the nominal diameter in enlarged sections of the hole, decreasing the rising velocity by a factor of at least five. The influence of the drillpipe rotation on the velocity profile is also difficult to account for. There are equations available for helical flow, but there is debate about whether fluid elements actually follow a helical path in the presence of rotation, and these equations were derived for drillpipe rotating concentrically in a vertical hole. In practice, the drillpipe whirls around in a seemingly random manner, particularly in deviated wellbores. Furthermore, equations for flow in eccentric annuli show that the annular velocity is greatly reduced when the drillpipe lies against the low side of the hole (as in directionally drilled wells); therefore, equations based on concentric annuli are seriously in error. Neither is there a way to account for the influence of thixotropy on the viscosity of the mud as the mud rises in the annulus. The high shear rates in the drillpipe and bit reduce the structural component of the viscosity to a very low value. The shear rates in the annulus are far lower, but change in each annular section, depending upon the drill collar, drillpipe, casing diameters, and degree of hole enlargement. The viscosity adjusts to each shear rate, but may take time to do so, and might never reach an equilibrium value (except in long sections of gauge or cased hole). To summarize, accurate pressure losses in the drillpipe and bit are reasonably easy to predict, but pressure losses in the annulus are much more questionable; however, quite accurate losses are obtained for the whole circulatory system because the annular loss (usually) forms such a small percentage of the total loss. The rigorous flow equations and testing procedures described in this document are suitable for laboratory. A number of methods of making wellsite hydraulic calculations are published, the complexity of which varies according to the authors’ acceptable degree of accuracy. ―When drilling in formations that enlarge significantly, calculate the pressure loss in the drillpipe and in the bit nozzles and subtract this figure from the sum of the standpipe pressure. The resulting figure is the annular pressure loss.‖ The equivalent circulating density(ECD) is defined as the effective mud weight at a given depth, created by the total hydrostatic (including cuttings pressure) and dynamic (friction loss) pressures. 4.4.2 Fricti onal Pressure Loss Model

The standard API methods for drilling hydraulics assume either a Power Law or Bingham plastic rheology model. As presented in the preceding section, most drilling fluids correspond more closely to the Herschel-Bulkley model. This distinction is particularly important for the annular geometries that are typical of normal drilling conditions where shear rates are low, the Power Law model underestimates, and the Bingham model overestimates frictional pressure drops. These two models also respectively underestimate and overestimate the pump rates required for transition from laminar to turbulent flow. The model described briefly below is developed for non-Newtonian flow through pipes and concentric annuli. The method is based upon relating non-Newtonian flows to Newtonian flows, and the definition of an effective diameter is a key concept within the model. This concept is important because it accounts for both geometric and non-Newtonian effects on frictional pressure gradients in pipes and annuli. 70

The analysis is valid for laminar, transitional, and fully turbulent flow regimes. The method incorporates new transition criteria that account for the delay in flow transition with increasing ratio of inner to outer diameters in concentric annuli. When using the same viscometer data, the results from the analyses (included below) show that the transition from laminar to turbulent flow occurs at higher pump rates than for a Power Law fluid, but significantly lower than for the corresponding Bingham plastic. For turbulent flow, the Colebrook equation is modified so that the equation applies to non-Newtonian flows through pipes and annuli with smooth or rough walls. The method also accounts for the effects of wall roughness on frictional pressure gradients in transitional flow. The iterative solution proposed below is slightly more time-consuming than a direct calculation using explicit friction factors, but avoids the necessity for computationally expensive finite-difference or finite-element simulations (previously the standard for turbulent and transitional flow of Herschel-Bulkley fluids). Lamb’s diameter, hydraulic diameter, and equivalent diameter are defined in the following equations : Lamb’s Diameter

DL 



DO2  Di2  DO2  Di2 ln DO / Di 



Hydraulic Diameter

Dhy  DO  Di Equivalent Diameter

Deq  DL2 / Dhy The calculations must then be separated into Newtonian and non-Newtonian flow regimes, as found in the following sections. 4.4.2.1 Newtonian Flow

  

Calculations are given for the following flow regimes of a Newtonian fluid: A. laminar pipe flow B.

laminar annular flow

C. turbulent pipe flow D. turbulent annular flow E. transitional pipe and annular flow 4.4.2.1.1 Laminar Pipe Flow The Reynolds number (Re) is defined as Re   f VD /  , where D is the pipe inner diameter, V is the fluid velocity in the pipe,

 is the Newtonian viscosity, and  f is the local fluid

density. The laminar friction factor is given as follows:

flam  16 / Re

4-17

The corresponding frictional pressure gradient is given by the following:

71

P  2 f lam  f V 2 / D L

4-18

4.4.2.1.2 Laminar Annular Flow The analysis for annular flow is similar to that of pipe flow, except that the Reynolds number for annular flow is based on the effective diameter Re   f VDeq /  and the frictional pressure gradient is based on the hydraulic diameter, as follows:

P  2 f lam  f V 2 / Dhy L

4-19

4.4.2.1.3 Turbulent Pipe Flow The Colebrook equation-modified for pipe roughness (  ) is given by the following implicit equation:

 1 1.255     4 log10 0.269  / D    fturb Re fturb    

4-20

4.4.2.1.4 Turbulent Annular Flow The Colebrook formulation (Equation 4-20) is also used for turbulent annular flow, except that the Reynolds number is based upon the equivalent diameter. 4.4.2.1.5 Transitional Pipe and Annular Flow Following the analysis given by Reed and Pilehvari, PowerPlan defines the intermediate (f int ) and transitional (ftr ) friction factors given by the following equations :

ftr  1.390532  10 9 Re2









8 fint  ftr8  fturb 12 ftot  fint12  flam

1 / 8

1 / 12

4-21 4-22

ftot is the friction factor used throughout the transition zone. The flow is then determined to be transitional and laminar if f tot < 16.1 / Re, unless the friction factor is within 1% of the turbulent friction factor calculated from the extended Colebrook equation. The corresponding pipe and annular pressure drops are then expressed as in Equations 4-18 and 4-19 respectively, but with the total friction factor (ftot) used in the definition. 4.4.2.1 Power Law Fluid

  K n Calculations are given for the following regimes of a Power Law fluid: A. laminar pipe flow B. laminar annular flow C. turbulent pipe and annular flow D. transitional pipe and annular flow 4.4.2.2.1 Laminar Pipe Flow

In laminar pipe flow an effective diameter (such as the friction factor) is defined. The Reynolds number relation for laminar flow is still given by Equation 4-17. Thus, the following applies: 72

Deff  4nD /(3n  1) The average wall shear rate is defined as follows:

  8V / Deff The effective viscosity becomes as follows:

eff  K 8V / Deff n1 Consequently, the Reynolds number and friction factor are as follows:

Re   f VDeff / eff

flam  16 / Re 4.4.2.2.2 Laminar Annular Flow This calculation is a little more complex, due to the nature of the geometry; however, a good solution is given by Reed and Pilehvari. First, the parameters are given that describe the new effective diameter and allow for the effects of both the annular geometry and the non-Newtonian behavior of the fluid:

Y  0.37 n



Z  1  1  Di / DO 



Y 1/ Y

G  1  Z / 2 (3  Z )n  1/(4  Z )n The effective diameter is defined as follows:

Deff  ( DO  Di ) / G The pressure loss is given by the following:

P  4 K  8v  L  Dhy  Deff

   

n

4.4.2.2.3 Turbulent Pipe and Annular Flow The turbulent friction factor is modified for the non-Newtonian behavior by both the definition of the generalized Reynolds number (one based on the effective viscosity) and a modification for the Power Law index. These modifications are expressed as follows:

  1 1.255 n    4 log10 0.269  / D   0.75  n ( 1  n / 2 ) fturb   Re f turb  





For turbulent annular flow, the pipe diameter is replaced by the effective diameter (Deff) and the Reynolds number is calculated using the effective diameter. 4.4.2.2.3 Transitional Pipe and Annular Flow （过渡管流和环空流） For transitional pipe and annular flow, a similar approach is taken as for that of the Newtonian fluid; however, the friction factor must be modified again for the non-Newtonian behavior as follows (with the appropriate choice of pipe or annulus Reynolds number):

73

f temp 

9.49  10 9 2 (4.767  2.167 n 2 ) Re

fint and ftot are defined as in Equations 4-22 and 4-13, with the same criteria to decide the transitions between laminar/transitional and transitional/turbulent, as for the Newtonian case. Finally, the pressure losses are given by Equations 4-18 and 4-19, with the total friction factor (f tot) used in their definitions 4.5 Rheologieal Properties Required for Optimum Performance（流变特性与优化钻 井） The drilling engineer controls mud properties to: A. Minimize pumping costs. B.

Maximize bit penetration rates.

C. D.

Lift drill cuttings efficiently. Lower swab and surge pressures, and pressure required to break circulation.

E. F.

Separate drill solids and entrained gas at the surface. Minimize hole erosion.

The rheological requirements for these diverse purposes often conflict, so that it is necessary to optimize the mud properties in order to obtain the best overall performance. The properties required for each purpose are discussed separately below. 4.5.1 Pumping Capacities（泵排量）

Pump capacity must be large enough to maintain a rising velocity in the widest section of the annulus sufficient to lift the drill cuttings efficiently. The pump horsepower required to do this will depend almost entirely on flow conditions in the drill pipe and through the bit nozzles. The pressure loss through the bit nozzles is not affected by the rheological properties, and the pressure loss in the drill pipe is only affected to a minor extent because, there, flow is usually turbulent. As far as rheology is concerned, there are only two possible ways to lower the pressure loss in the drill pipe. One is to increase the carrying capacity of mud (as discussed later in this chapter) so that the circulation rate can be lowered. The other is to use a low solids polymer mud, whose friction reducing properties will minimize turbulent pressure losses, a solution which is practical only under certain rather limited well conditions 4.5.2 Effect of Mud Properties on Bit Penetration Rate（钻井泥浆性能对机械钻速的影响）

Maintaining the viscosity at a low value is a major factor in promoting fast penetration rates. The relevant viscosity is the effective viscosity at the shear rate prevailing at the bit, which is of the order of 100,000 reciprocal seconds. 4.5.3 Hole Cleaning（钻孔清洗）

Before discussing the optimum rheological properties required for lifting drill cuttings, it is first necessary to review the basic mechanisms involved. The rate at which a rising column of fluid will carry solid particles upwards depends on the difference between the velocity of the fluid and the tendency of the particle to fall through the fluid under the influence of gravity. In a still liquid, a falling particle soon acquires a constant downward velocity, known as the terminal 74

settling velocity（自由沉降速度）, which depends on the difference in density between the particle and the liquid; the size and shape of the particle; the viscosity of the liquid, and on whether or not the rate of fall is sufficient to cause turbulence in the immediate vicinity of the particle. In the case of spheres falling through a Newtonian liquid, the Reynolds number is given by:

N R eP, 

d p vt  f



where dp is the diameter of the sphere, v, the terminal settling velocity,  f the density of the fluid, and



its viscosity. Under laminar flow conditions the terminal flow velocity is given by

Stokes’ law:

vt 

2 gd p2 36



p  f 

where  p is the density of the particle. Under turbulent flow c onditions the terminal settling velocity is given by Rittinger's formula:

 d p ( p   f )   vt  9     f   Predicting the terminal velocity of drill cuttings is much more difficult. For one thing, there is the wide range of particles sizes and the particles have irregular shapes: For another, there is the non-Newtonian nature of most drilling fluids. Terminal velocities in turbulent fall are somewhat easier to predict because the rate of fall is not affected by the rheological properties. Walker and Mayer proposed the following equation for flat particles falling face down, ( which is the normal orientation for turbulent fall):

 2 gd p (  p   f )   vt     1 . 12  f   Terminal veloc ities predicted by this equation correlated well with experimental data obtained with artificial cuttings of uniform size and shape. In a drilling well, cuttings fall under still settling conditions whenever circulation is stopped. In a Newtonian fluid the settling velocity is finite, no matter how viscous the fluid, but, because of the enormous length of the settling column, only a small proportion of the cuttings reach the bottom unless the viscosity approaches that of water. In a non-Newtonian fluid the settling velocity depends on the difference between the stress (τ ) created by the difference in gravity (  p   f ) and the gel strength of the mud (S). Whenτ < S, then vt , is zero, and the cutting is suspended. The initial gel strength of most muds is too low to suspend large cuttings, and suspension depends on the increase of gel strength with time. In a rising column of fluid, a particle will move upward if the velocity of the fluid is greater than the settling veloc ity of the particle. However, the particle slips in the rising column, so that the upward velocity of the cutting is less than the annular velocity. Sifferman et al defined hole-cleaning efficiency in terms of a transport ratio（携带比）, derived as follows:

75

vc  va  vs

Fig. 4-14 Unequal forces on flat disc when mud flow is laminar

Fig. 4-13 Driscs recycling in the annulus. Drill pipe stationary

where vc is the net rising velocity of the cutting, va is the annular velocity, and, vs is the slip velocity of the cutting. Dividing both sides of the equation by va , gives

vc v  transportr atio  1  s va va One reason for poor transport efficiency was shown experimentally by Williams and Bruce to be that fiat cuttings tend to recycle locally as shown in Figure 4-13. This recycling action is presumed to be caused by the parabolic shape of the laminar velocity profile, which subjects a fiat cutting to unequal forces (see Figure 4-14). In consequence, they turn on edge and migrate to the sides of the annulus, where they descend some distance before migrating back towards the center. The downward descent is caused partly by the low velocity prevailing at the walls, and partly by the edgeways orientation of the cutting.

In general, rotation of the drill pipe improves the transport ratio because it imparts a helical

76

motion to the cuttings in the vicinity of the drill pipe (see Figure 4-15). Theoretically, turbulent flow should improve the transport ratio because the flatter profile eliminates the turning moment (Figure 4-16), but experimental evidence on this point is not consistent, possibly because of differences in experimental conditions, such as the size and shape of the cuttings.

Fig. 4-15 Helical motion of discs when the drill pipe is rotating

Fig. 4-16 Driscs transported in turbulent flow (center pipe stationary)

4.5.4 Opti mum Annular Velocity（最优流速）

Although any velocity greater than the settling veloc ity of the largest cutting will theoretically lift all the cuttings to surface eventually, too low an annular velocity will lead to an undesirably high concentration of cuttings in the annulus. Because of slip, the concentration of cuttings depends on the transport ratio as well as the volumetric flow rate and the rate of cuttings generation by the bit. Experience has shown that cutting concentrations more than about 5% by volume cause tight hole, or struck pipe, when circulation is stopped for any reason. 4.5.5 Opti mum Rheologieal Properties for Hole Cleaning（清洁钻孔的最优流变性能）

On general principles, a mud with predominantly structural viscosity as indicated by a high ratio of yield point to plastic viscosity, or a low flow behavior index, n--is desirable for hole cleaning purposes. Such a mud will be a shear-thinning mud, so that the effective viscosity will increase in the enlarged sections, where fluid velocities are low, and decrease in gauge hole sections, where fluid velocities are high. 4.6 The Importance of Hole Stability(稳定孔壁的重要性) The primary objective of the drilling engineer must be to maintain hole stability, because a 77

gauge hole can be cleaned with a low viscosity mud, in which case progress will be rapid and problems will be few. If the hole enlarges, as it inevitably will in many formations, visc osity and gel strengths will have to be increased in order to clean the hole, but the higher viscosities and gel structures will decrease penetration rates and cause high swabbing and surge pressures, gas cutting, etc. The conflicting rheological requirements will be minimized by using a shear-thinning mud, which sets to a gel which is sufficient to suspend cuttings when circulation is stopped, but which breaks up quickly to a thin fluid when disturbed. Such a mud will have a high yield point/plastic viscosity ratio, and a low flow-behavior index, n. Techniques for controlling the rheological requirements in the field are beyond the scope of this chapter, but it may be said that high YP/PV ratios are best obtained by lowering the plastic viscosity rather than by increasing the yield point. As a general rule, therefore, maintain the lowest possible plastic viscosity by mechanical removal of drilled solids at the surface, and keep the yield point no higher than required to provide adequate carrying capacity. The yield point is controlled by adding or withholding thinners when drilling in colloidal clays, and by adding bentonite when drilling in other formations. Exercises 1. Give the following concepts, rheology, shear stress, shear rate. 2. Write the equation of Newtonian fluid, explain the meaning of viscosity in this equation, and describe the character of Newtonian fluid. Give the example drilling fluids which behave as Newtonian fluid. 3. What are non-Newtonian fluids, give the distinction of them from Newtonian fluid. 4. Write the equations of Bingham Flow Model(Bingham Plastic Fluids) and Power Law Model(Pseudoplastic Fluids), and explain the parameters, i.e. Yield Point(  0 ), Plastic Viscosity (  p ), consistency index K, and flow behavior index n. 5. Explain the shear-thinning behavior of drilling fluids and discuss its effects on drilling operation. 6. Using a 6-velocity Bob Viscometer to measure a fluid, and the result is that

600  35,

300  23, calculate the following parameters, Effective Viscosity e , Yield Point(  0 ), Plastic Viscosity (  p ), consistency index K, and flow behavior index n. 7. The Baroid-286 Viscometer readings of a drilling fluid with the density of 1.32 g/cm3 is given in the following table: rpm 600 400 Dial readings

52.3

38.8

300

200

100

80

60

40

20

6

3

32.8

25.5

18.5

16.5

14.0

11.5

10.0

8.2

7.5

-1

（1) Take shear stress γ(s )as X-axis and τ(Pa) as Y-axis, draw the rheological curve of this drilling fluid, and judge what flow model its rheological properties suite best? （2) Calculate its apparent viscosity at each rpm and observe the change of the apparent viscosities when the shear stress increases. 8. Write the equations of Casson Model and Herschel-Bulkley Model and explicate the advantage of them. 78

9. Discuss the effects of rheological properties on optimum performance.

79

CHAPTER 5 THE FILTRATION PROPERTIES OF DRILLING FLUIDS In this chapter, we discuss the principles of static and dynamic filtration, the factors affecting filtrate volu me, the measurement of filtration, and the measures to control, adjust the filtrat ion properties of drilling fluids.

5.1 Filtration and Filtration Procedures（失水和失水过程） 5.1.1 The Filtration Properties（滤失性能） In order to prevent format ion fluids fro m entering the borehole, the hydrostatic pressure(静液压力 ) of the mud colu mn must be greater than the pressure of the flui ds in the pores of the formation(地层孔 隙 压 力 ). Consequently, mud tends to invade the permeable formations. Massive loss of mud into the format ion usually does not occur, because the mud solids are filtered out onto the walls of the hole, forming a cake（泥饼） of relatively low permeability, through which only filtrate( 滤液 ) can pass. Muds must be treated to keep cake permeab ility as lo w as possible in order to maintain a stable borehole and to minimize filt rate invasion of, and damage to, potentially productive horizons. Furthermore, h igh cake permeab ility results in thick filter cakes（滤饼） , which reduce the effective diameter of the hole and cause various problems, such as excessive torque when

Fig. 5-1 The filtration cake

rotating the pipe, excessive drag when pulling it, and high swab and

on the different formation

surge pressures. Thick cakes may cause the drill pipe to stick by a mechanis m known as differential sticking, which may result in an expensive fishing job. Figure 5-1 shows the filter cake on different format ions. It can be observed that on high permeable formations such as sand, gravel and limestone with abundant fractures, thick filter cakes formed, and on low permeab le formations, such as shale, silt, limestone and the other compact formation, only thin or even no cakes can be seen. Two types of filtrat ion are involved in d rilling an o il well: static filtration（静滤失） , which takes place when the mud is not being circulated, and the filter cake gro ws undisturbed, and dynamic filtration（动滤失）, when the mud is being circu lated and the growth of the filter cake is limited by the erosive action（冲蚀作用） of the mud stream. Dynamic filtration rates are much higher than static rates, and most of the filtrate invading subsurface formations does so under dynamic conditions. The filtration properties of drilling flu ids are usually evaluated and controlled by the API filter loss test, which is a static test, and is therefore not a reliable guide to downhole filtrat ion unless the differences between static and dynamic filtration are appreciated, and the test results interpreted accordingly. 5.1.2 The Overall Procedures of Filtrati on（失水全过程）

The filtration procedure of drilling fluids comprises three stages, i.e., spurt loss, dynamic filtration and static filtration. 5.1.2.1 Spurt Loss(瞬时失水)

80

On the moment that drill bit crushes the bottom rock and creates new free surfaces, the drilling fluid contacts the new rock, then the free water in the drilling fluids begin to invade into the formation pores, until the filter cakes of the solids and polymers in the drilling fluid forms on the wall of borehole, the filtration happens during this time is called spurt loss of initial loss. The time for spurt loss is very short, and because there is no cake on the surface of bottom rock, the filtration rate is high. 5.1.2.2 Dynamic Filtration(动失水) Following the spur loss, when the drilling fluid circulates, filtration continues and cakes are created. When the velocity of the cake increase equals that of the cake being eroded, then a dynamic balance is gained. The filtration happens during this time is called dynamic filtration, which features that the filtration rate at the beginning is large, then decreases and stabilizes at a certain value because of the higher pressure difference between the total pressures of hydrostatic and annular friction pressure and formation pore pressure. 5.1.2.3 Static Filtration(静滤失) When drilling fluid circulation is suspended, e.g. during trip operation, the erosion disappears, the pressure difference is lowered (only between hydrostatic and formation pore pressure), then cakes thickens gradually, and the filtration rates declines.

Fig.5-2 Relative static and dynamic filtration in the bore hole

After the trip ends, the circulation restarts, the dynamic filtration happens again. The various stages of dynamic filtration are shown in Figure 5-2. Fro m T0 to T1 , the filtration rate decreases and the cake thickness increases. Fro m T 0 to T1 the thickness of the cake remains constant, but the filtrat ion rate continues to decrease, because, according to Outmans, the filter cake continues to compact. (Presumab ly, therefore, the rate of deposition equals the rate of co mpaction). Another explanation is given by Prokop, who suggested that the permeability o f the cake decreases because of a classifying action as the mud stream erodes and redeposits particles in the cake’s surface. At time T2 , equilibriu m conditions are reached, and both the filtration rate and the cake thickness remain constant.

5.2 The Static Filtration and Affecting Factors（静滤失及其影响因素） 5.2.1 The Static Filtration Equation(静滤失方程) 81

The flo w of mud filtrate through a mud cake is described by Darcy's law. Thus, the rate of filtrat ion is given by dV f dt



KAP hmc

5-1

where dV f = the filtrat ion rate, cm3 /s, dt

K= the permeability of the mud cake, Darcies, A = the area of the filter paper, cm2 ,

P = the pressure drop across the mud cake, 105 Pa,

 = the viscosity of the mud filtrate, cp, and

hmc = the thickness of the filter (mud) cake, cm. At any time, t, during the filtration process, the volume of solids in the mud that has been filtered is equal to the volume of solids depos ited in the filter cake:

f smVm  f sc hmc A where

f sm is the volume fraction of solids in the mud and f sc is the volu me fract ion of solids in the

cake, or

f sm (hmc A  v f )  f sc hmc A Therefore,

hmc 

f smV f A( f sc  f sm )



Vf f A( sc  1) f sm

5-2

Substitute this expression for h mc into Eq. 5-1 and integrating,



Vf

0

V f2 2

 KAp  f sc A  1dt 0   f sm 

V f dV f  



t

 f  A2  sc  1pt   f sm 

K

or

 f  t V f  A 2 Kp sc  1  f sm  

5-3

Formula 5-3 is called static filtration equation, which shows that the filtration loss per unit area is proportional to square root of the permeability of the filter cake K, the solid content in cake incorporating that in drilling fluid(f sc/f sm -1), the filter pressure difference p , and filter time t directly, but proportional to filtrate viscosity



inversely.

5.2.2 The Factors Affecting the Static Filtration(静失水影响因素) 82

5.2.2.1 Relationship between Filtrate Volume and Time Larsen found that if a mud was filtered through paper at constant temperature and pressure,

was proportional to

f sc/ f sm

t

Vf

, apart fro m a small zero error(零点误差 ). It followed that, for a given mud,

and K in Eq. 5-3 were constant with respect to time. Although this finding is not strictly true

for all muds, it is close enough for practical purposes, and forms the basis for the mechanics of static filtration as presently interpreted. Fig. 5-3 shows a typical p lot of cumulative filtrate volume

（累计滤失量）versus time plotted on a square root scale. The intercept on the V axis marks the zero error. The zero error, commonly called the mud spurt(初失水 ), is largely caused by the tendency of the finer mud particles to pass through the filter paper until its pores become plugged. Thereafter only filtrate is expressed, and the curve becomes linear. W ith most muds the zero

Fig.5-3 Example filter press data.

error is small, and is often neglected, but it can be substantial when filtration takes place against porous rocks. So me muds plug filter paper almost instantly, in wh ich case the zero error is negative, and represents the volume between the paper and the discharge nipple(排液

嘴 ). Larsen’s experimental results showed that for a given pressure, Eq. 5-3 may be written:

V f  Vsp  A (C  t )

5-4

where Vsp is the zero error, and C is a constant given by

C

 2 KP  f sc   1   f sm 

Note that Eq.5-4 and Fig. 5-2 indicate that the filtrate volu me is proportional to the square root of the time period used. Thus, the filtrate collected after 7.5 min should be about half the filtrate collected after 30 min. It is co mmon practice to report twice the 7.5-min filtrate volu me as the API water loss when the 30-min filtrate volu me exceeds the capacity of the filtrate receiver. Ho wever, as shown in Fig. 5.3, a spurt loss volume of filtrate, Vsp , is often observed before the porosity and permeability of the filter cake stabilizes and Eq. 5-3 becomes applicable. If a significant spurt loss is observed, the following equation should be used to ext rapolate the 7.5-min water loss to the standard API water loss.

V30  2(V7.5  Vsp )  Vsp The best method for determin ing spurt loss is to plot V vs.

5-5

t

and extrapolate to zero t ime as

shown in Fig.5-3. The API lo w-pressure static filtrat ion press in use today is based on an original design by P.H. Jones. The test is used to determine A) the filtration rate through a standard filter paper and B) the rate at which the mud cake th ickness increases on the standard filter paper under standard test conditions. This test is indicative of the rate at which permeable formations are sealed by the deposition of a mud cake after being penetrated by the bit. The standard dimensions are: filtrat ion area, 45.8 cm2 (7.l in 2 ); minimu m height, 6.4 cm (2.5 in); and standard filter paper, Whatman 50, S & S No. 576, or equivalent.

83

Pressure of 7.0 kg/cm2 (100 psi), fro m either a nitrogen cylinder or a carbon dio xide cartridge, is applied at the top of the cell. The amount of filtrate d ischarged in 30 minutes is measured, as is the thickness of the filter cake to the nearest 1 mm (1/32 in.) after washing off the excess mud with a gentle stream of water. The filtrate volu me that would accu mulate in 30 minutes can be predicted fro m the volu me,

observed at time

t1

Vf

fro m the equations:

V f 30  Vsp  (V f 1  Vsp )

t30 5-6

t1

For example, the 30 minute filtrate volu me is sometimes predicted by measuring the filtrate volu me at 7.5 minutes, and doubling the value obtained, since

30 / 7.5  2 .

5.2.2.2 Relationship Between Pressure and Filtrate Volume

According to Equation 5-3, of

V f should be proportional to P, and a log-log plot（双对数坐标图）

V f versus P should yield a straight line with a slope of 0.5, assuming all factors remained constant.

Actually, this condition is never met because mud filter cakes are to a greater or lesser extent compressible（可压缩的） , so that the permeability is not constant, but decreases with increase in pressure. Thus:

V f P x where the exponent（指数）

x varies fro m mud to mud, but is always less than 0.5, as shown in

Figure 5-4.

Fig.5-4 Effect of pressure on filtrate volume

x depends largely on the size and shape of t he particles composing the cake（泥饼中颗粒的尺寸和形状） . Bentonite cakes, for examp le, are so co mpressible that x is The value of the exponent

84

zero, and

V f is constant with respect to P. The reason for this behavior is that bentonite is almost

entirely co mposed of finely-div ided platelets of mont morillonite, which tend to align more nearly parallel to the substrate with increase in pressure. Thus the permeability of the cake is reduced to a much greater extent than would be the case with a cake co mposed of, for examp le, rigid spheres（刚性

颗粒） . With other drilling mud clays it has been found experimentally that the x exponent varies fro m zero to about 0.2, so it appears that filtration rate is relatively insensitive（不敏感的）to changes in pressure. In practice, it is usually simpler to make the filtrat ion test at the pressure of interest.

Fig. 5-5 Viscosity of water at various temperatures

5.2.2.3 Relationship between Temperature and Filtration Volume Increase in temperature may increase the filtrate volu me in several ways. In the first place, it reduces the viscosity of the filtrate, and, therefore, the filtrate volu me increases according to Equation 5.3. The viscosities of water are shown over a range of temperatures in Table 5-1, and over an extended range, for water only, in Figure 5-5. It is evident that changes in temperature may have a substantial effect on filtrate volu me because of changes in filt rate viscosity. For examp le, the filtrate volu me at 100℃(212 ℉) would be about

1  1.88 times as large as the volume at 20℃ 0.284

(68 ℉). Table 5-1 The viscosities of water at various temperatures Temp. ℃

0

12

20

30

40

60

80

100

130

180

230

300

Viscosity/mPa•s

1.729

1.308

1.005

0.081

0.656

0.469

0.356

0.284

0.212

0.150

0.116

0.086

5.3 The Filter Cake(滤饼) 5.3.1 Cake Thickness（滤饼厚度） Although cake thickness is the vital factor in problems associated with tight hole, pipe torque and drag, and differential sticking, little attention has been paid to it in the literature. Cake thickness is assumed to be proportional to filter loss, and therefore only filter loss needs to be specified. Actually, although cake thickness is related to filter loss, the specific relationship varies from mud to mud, 85

because the value of

V f / Vc ( Vc is the volume of the cake) depends on the concentration of solids

in the mud（泥浆中固相含量） and on the amount of water retained in the cake（泥饼中含水量）. The filter loss decreases with increase in the concentration of solids, but the cake volume increases, as shown in Figure 5-6: If an operator adds ext ra clay to a mud to reduce filter loss, he may believe that he is also reducing cake thickness, but he is actually increasing it.

Fig.5-6 Variation of filtrate volume, cake volume, and permeability with concentration of solids in a suspension of Altwarmbuechen clay.

The amount of water retained in the cakes of muds with different clay bases depends on the swelling properties（膨胀特性） of the clay minerals involved. Bentonite, for example, has strong swelling properties, and bentonitic cakes therefore have a comparatively high rat io of water to solids, and the V f

/ Vc rat io is correspondingly low. The percent water in the cake is quite a good measure of

the swelling properties of the clay base. To a lesser extent, cake thickness is determined by particle size （粒径） and particle-size distribution（粒径分布） . These parameters control the porosity of the cake （泥饼的孔隙度） , and therefore the bulk volu me relat ive to the grain volu me. The magnitude of these effects was shown by Bo et al, who measured the porosities of filter cakes（泥饼孔隙度）formed by mixing nine size grades of glass spheres. Their results may be summed up as follows: A.

Minimu m porosities were obtained when there was an even gradation of particle sizes（均匀分布

颗粒尺寸）(i.e., a linear particle size d istribution curve, as shown in Figures 5-7 a and b), because the smaller part icles then packed most densely in the pores between the larger particles.

86

Fig. 5-7 Permeabilities and porosities of filter cakes of glass spheres. k=permeability in darcies ρ =porosity

B.

Mixtures with a wide range of particle sizes（较大范围颗粒尺寸） had lower porosities than mixtu res with the same size distribution but narrower size range, (cf. Figure 5-7 a with b).

C.

An excess of small particles resulted in lower porosities than did an excess of large part icles.

5.3.2 The Permeability of the Filter Cake(滤饼渗透率) The permeab ility of the filter cake is the fundamental para meter that controls both static and dynamic filtration. It mo re t ruly reflects downhole filt ration behavior than does any other parameter. As a parameter for evaluating the filtrat ion properties of muds with d ifferent concentration of solids, it has the advantage over filtrate volu me in being independent of solids concentration. Furthermo re, cake permeab ility provides useful informat ion on the electrochemical conditions prevailing in the mud. 5.3.3 The Effect of Particle Size and Shape on Cake Permeability (颗粒直径和形状对滤饼渗透性 的影响) Kru mbein and Monk investigated the permeability of filter cakes of river sand by separating the sand into ten size fractions and recombining them to obtain two sets of mixtures. In one set, the mixtu res had increasingly large mean particle d iameters, but all had the same range of part icle sizes, which were defined in terms of a parameter phi as shown in Figure 5-8. In the other set, all the mixtu res had the same mean particle diameter, but increasingly wider ranges of particle sizes. The results showed that cake permeab ility decreased (1) with mean particle diameter, and (2) with increasing width of part icles size range (see Figure 5-8).

87

Fig.5-8. Expandable of a narrow (curve A) and a wide (curve B) particle size range

One might expect minimu m cake permeab ility with an even gradation of particle sizes. However, the experiments of Bo et al already referred to, showed that minimu m permeab ilit ies were obtained when there was an excess of particles at the fine end of the scale, and not when the size distribution curves were linear (see Figures 5-7 a and b). It would appear therefore that a uniform gradation of particle sizes is of secondary importance, but obviously there must be no major gaps, or the finer particles would pass through the pore openings between the larger ones. 5.3.4 Effect of Floccul ati on and Aggregati on on Cake Permeability（絮凝与聚结对泥饼渗透的影 响） Flocculation of muds causes the particles to associate in the form o f a loose, open network. Th is structure persists to a limited extent in filter cakes, causing considerable increases in permeability. The higher the filtration pressure, the more this structure is flattened, so both porosity and permeability decrease with increase in pressure. The greater the degree of flocculation, the greater the interparticle attractive forces（ 粒间吸引力）, and therefore the stronger the structure and the greater its resistance to pressure (see Fig. 5-9). The structure is even stronger if flocculation is accompanied by aggregation, because it is then built of thicker packets of clay platelets. Conversely, deflocculation（解絮凝） of a mud by the addition of a thinning agent （稀释剂） causes a decrease in cake permeab ility. Moreover, most thinners（稀释剂） are sodium salts, and the sodium ion may d isplace the polyvalent cations（高价阳离子） in the base exchange positions on the clay, thereby dispersing （分散） the clay aggregates, and further reducing cake permeab ility. Thus, the electrochemical conditions prevailing in a mud are a major factor in determining the permeab ility of its filter cake. As a generalization it may be said that cake permeabilities of flocculated muds are in the order of 10-2 md, those of untreated fresh-water muds are in the order of 10-3 md, and those of muds treated with thinning agents are in the order of 10-4 md. 5.3.5 The Bri dging Process(架桥过程) As already discussed, there is a mud spurt at the start of a filter test made on paper before filtrat ion proper begins, and, thereafter, filtrate volu me becomes proportional to the square root of the time interval. In the drilling well, mud spurts may be much larger when filtration takes place against the more permeab le rocks: In fact, they can be infinite (i.e., circulation is lost （循环液漏失） ) unless the

88

mud contains particles of the size required to bridge the pores of the rock, and thus establish a base on which the filter cake can form. On ly part icles of a certain size relative to the pore's size can bridge. Particles larger than the pore opening cannot enter the pore, and are swept away by the mud stream; particles considerably smaller than the opening invade the formation unhindered; but particles of a certain critical size stick at bottlenecks in the flo w channels, and form a bridge just inside the surface pores. Once a primary b ridge is established, successively smaller part icles, down to the fine co llo ids, are trapped, and thereafter only filt rate invades the formation. The mud spurt period is very brief, a matter o f a second or two at the most. As a result of the process just described, three zones of mud particles are established on or in a permeab le formation (see Figure 5-9).

Fig.5-9 Invasion of a permeable formation by mud solids.

A.

An external filter cake （外泥饼） on the walls of the borehole.

B.

An internal filter cake（内泥饼） , extending a couple of grain diameters into the formation.

C.

A zone invaded by the fine particles during the mud spurt period, which normally extends about an inch（ 25.4 mm） into the formation. Experimental results reported by Krueger and Vogel suggest that these fine particles do not initially cause much permeability impairment （渗透率损

害） , but may do so after filtrat ion has proceeded for so me hours, presumably because of migration（颗粒运移） and consequent pore blocking （孔隙堵塞） . When adequate bridging particles are lacking, the API filter test may give grossly misleading results. A mud might give a negligible loss on filter paper, but give a large one on a permeable formation downhole. The point was well illustrated by experimental data obtained by Beeson and Wright, extracts fro m wh ich are shown in Table 5-2. Note that the discrepancy between the gross loss on paper and that on the porous med ia was greater with unconsolidated sand than with consolidated rocks, even when the permeability of the latter was higher. Note also that the discrepancies between the net filter loss on paper and on porous media increased with increase in spurt loss. Ev idently the mud spurt plugs the cores to such an extent that the pressure drop within the core beco mes significant, thereby reducing the drop across the cake, and reducing cake compaction. Table5-2 Effect of Filtration Medium on Mud S purt

89

With regard to the crit ical size required fo r bridging, it was shown by Coberly that because of jamming, particles down to one-third the size of a circular screen opening would bridge that opening. Abrams showed that particles whose median diameter was about one-third the med ian pore size of a 5 darcy sand pack would bridge that pack. In order to form an effective base for a filter cake, a mud must therefore contain primary bridging particles ranging in size fro m slightly less than the largest pore opening in the formation about to be drilled, down to about one-third that size. In addition, there must be smaller particles ranging down to colloidal size, to bridge the smaller format ion pores and the interstices（空隙 , 裂缝） between the coarser bridging particles.

5.4 Dynamic Filtration(动失水) Under the condition of dynamic filtration, the growth of the filter cake is limited by the erosive action of the mud stream. When the surface of the rock is first exposed, the rate o f filtrat ion is very high, and the cake grows rapidly. Ho wever, the growth rate decreases as time passes, until eventually it is equal to the erosion rate; thereafter the thickness of the cake is constant. Under equilibrium dynamic conditions（动平衡条件下）, therefore, the rate of filt ration depends on the thickness and permeability of the cake, and is governed by Darcy's law (Equation 5-1), whereas under static conditions cake thickness increases ad infinitum（无限） , and the rate of filtration is governed by Equation 5-3. Dynamic filter cakes differ fro m static cakes in that the soft surface layers of the static cake are not present in the dynamic cake, because its surface is eroded to an extent that depends on the shear stress exerted by hydrodynamic force （水力） of the mud stream relative to the shear strength of the cake’s upper layers. Both low-temperature and high-pressure API filter presses are operated under static conditions that is, the mud is not flo wing past the cake as filtration takes place. Other presses have been designed to model mo re accurately the filtration process wherein mud is flowed past the cake, as it does in the wellbore. Such presses that model. Dynamic filtration have shown that after a given period of t ime the mud cake thickness remains constant - that is, the cake is eroded as fast as it is being deposited. Thus , dynamic-filtrat ion rates are higher than static filtration rates. With a constant thickness cake, integrating Eq.5-1, we have

90

vf 

kApt hmc

5-7

A standard dynamic filt ration test has not been developed to date. Field mud testing uses the static filtration test to characterize the filtration quality of the mud.

Unfortunately, there are no reliable

guidelines for correlating static and dynamic filtrat ion rates. Our ability to predict quantitatively filtration rates in the wellbore during various drilling operations remains questionable. Prokop [23] measured dynamic filtrat ion rates in a laboratory tester, in wh ich mud flo wed through a concentric hole in a cylindrical artificial core. Table 5-3 shows the equilibriu m cake thickness thus obtained with a large number of laboratory muds. Table 5-3 Equilibrium cake thickness under dynamic filtration

Mud circulated through a 2 in (5.08 cm) diameter hole in consolidated sand. Turbulent flow. Filtration pressure 350 psi (24.6 kg/cm2)

Exercise 1.

A filtrate volu me of 5 cm3 is collected in 10 min in a filter press having an area of 90 cm2 . A spurt loss of 0.5 cm3 was observed. Compute the API water loss.

2.

A 15-in. hole is drilled to a depth of 4,000 ft. The API water loss of the mud is 10 ml. Approximately 30% of the lithology is permeable sandstone and the rest is impermeable shale. 1)

Construct a plot of estimated filtration loss in barrels vs. time in hours (0 to 24 hours) that would occur if the hole were drilled instantaneously. Assume porosity is 0.25.

2)

Answer: 42.4 bbl after 24 hours. Compute the radius of the invaded zone for Part a in inches after 24 hours.

3)

Answer: 9.62 in. Repeat Part a assuming a drilling rate of 200 ft/hr. Answer: 31.6 bbl after 24 hours.

4)

Do you feel the API water loss test is representative of conditions in the well during drilling operations? (Hint: Find an article on "dynamic filtration.")

91

CHAPTER 6

MAKE-UP MATERIALS AND ADDITIVES FOR

DRILLING FLUIDS Drilling fluid materials include basic materials and chemical addit ives, the former denote clay and water, the latter are the chemicals used for adjusting the pro perties of the drilling fluid. According to their chemical characteristics they are classified as inorganic chemicals, organic chemicals and surfactant. And according to their functions they are: 1) thinner, 2) filtrat ion reducer, 3) v iscosifier, 4) shale inhibitor, 5) lost circulat ion material, 6) lubricant, 7) flocculant 8) emu lsifier, 9) foaming agent, 10) clay, 11) weighting agent, 12) pipe-freeing agent, 13) corrosion inhibito r, 14) defoamer, 15) bactericide, 16) the others. This chapter focuses on some co mmon materials and ad ditives.

6.1 Water(水) Water is the most important single substance involved in drilling fluids technology. Water in the formations drilled is usually the limiting factor in air drilling, so very few wells are drilled with dry air. In all other instances, at some time in the course of drilling, water is the majo r co mponent (by volu me) of the drilling fluid. Even when the use of water-mud is discontinued in favor of an oil-mud or a foam, water continues to play an important role in the performance of the drilling fluid. The un usual characteristics of water affect each step in the drilling operation fro m spud -in to co mplet ion, and the availability and chemical content of the makeup water must be considered in the planning stage. See

Chapter 2 ―Treatment of Make -up Water‖. 6.2 Bentonite(膨润土) Grim and Nueven defined Bentonite as "Any clay which is composed dominantly of a smectite(蒙

脱石 ) clay mineral, and whose physical properties are dictated by this clay mineral‖. Bentonite has also been defined as consisting of fine-grained(有细密纹理的 ) clays that contain not less than 85% mont morillonite(蒙脱石 ). In mud parlance, bentonite is classilicd as sodium bentonite（钠土） or calcium bentonite（钙土）, depending on the dominant exchangeable cation. Correspondingly, in terms of performance, bentonite is classed as high yield（高造浆） and low yield （低造浆） . The heterogeneous nature of bentonite was shown by X-ray diffraction patterns（ X 光衍射图谱） and cation-exchange data （阳离子交换数据） for several samples of Wyoming bentonite separated into three fractions by centrifuging(离心 ) the suspensions. A correlation was observed between the plastic viscosity and gel strength properties as affected by the surface area and the exchangeable cation in centrifuged fractions. The relat ively coarse fractions (least surface area) contained main ly calciu m as exchangeable cation and showed distinctly lower viscosity and gel strength than the finer fractions in wh ich sodium was dominant.

6.2.1 Mining and Processing(开采与加工) After a potentially co mmercial bentonite deposit(矿床) has been located, auger or core drills are used to collect samp les for evaluation. If results are favorable, p its are laid out, with particu lar consideration given to quality and tonnage of recoverable bentonite, ratio of required over-burden 92

removal to recoverable bentonite, drainage, and reclamation. M inable bentonite beds vary in thickness from a minimu m of two feet. The maximu m stripping depth is about sixty feet. After the overburden has been removed, the bed may be resampled on clos er spacing. Based on test results, the pit is marked fo r selective mining. A co mmon practice is to expose the clay to air for several months, during which time the bed may be plowed or ripped. This practice pro motes drying and improves the quality of the clay. The bentonite areas of differing quality are mined separately and hauled to stockpiles located at the processing plant. Fro m the stockpiles, the selected bentonite is passed through a slicer(切片机 )or cutter for sizing, and then into a dryer where the mo isture content is reduced fro m 15-35% to 8-10%. The dried bentonite is ground in roller mills(滚筒辗粉机 ). Based on the results of performance tests, on samples of the clay, s mall amounts of polyacryl ates(聚丙烯酸酯) (maximu m of 2 lb/ton) may be added to the mill feed. Cyclone collectors extract the minus-200-mesh product, which is trans ferred to storage in silos pending bagging or loading into hopper cars. Bentonite furn ished to API specifications must satisfy the requirements listed in Table 6 -1. Table 6-1 API S pecification for Bentonite M oisture at point of manufacture

10%(maximum)

Wet screen analysis(200 mesh US screen residue)

4%(maximum)

Properties of a suspension of 22.5g bentonite(as received) in 350 ml dist illed water; aged overnight; restirred 5 min. Viscometer dial reading 600 rpm

30 (minimum)

Yield point

3



Plastic Viscosity (maximum)

Filtrate loss -(100 psi 24  3℃.)

15 ml (maximum)

6.2.2 Bentonite in Drilling Mud(钻井泥浆用膨润土) Bentonite is added to fresh water o r to fresh-water muds for one or mo re of the following purposes: (1) to increase hole cleaning capability; (2) to reduce water seepage or filtration into permeable formations; (3) to form a thin filter cake of lo w permeability; (4) to pro mote hole stability in poorly cemented format ions, and (5) to avoid or overco me loss of circulat ion. The amount to be added will, of course, vary with specific conditions but approximate quantities are suggested in Table 6-2. Table 6-2 Approximate Amounts for some Application Added to Fresh Water

Added to Fresh Water Mud

(lb/bbl)

(kg/m3)

(lb/bbl)

(kg/m3)

Normal drilling conditions

13-22

35-60

4-10

11-28

Stabilize caving formations

25-35

70-100

9-18

25-50

Loss of circulation

30-40

85-110

10-20

28-56

Loss of circulation plug

Added to Diesel Oil (lb/bbl)

(kg/m3)

93

400

1000

6.2.3 Beneficiated and Super-Yield Bentonite（粘土改性提高造浆率） Terms such as peptized（胶溶） , beneficiated and extra-high yield describe bentonites to which organic polymers(有机聚合物 ) (and sometimes also soda ash) have been added during processing. These products made with Western bentonite in America are useful as starting or spud muds（开孔泥

浆）, in low-solids muds（低固相泥浆）, and in applications where cost of trans portation is extremely high. Less than half as much of such a material is needed compared to the amount of API-specificat ion bentonite.

6.3 Materials to Increase Density(加重材料) An important function of drilling mud is the control of format ion fluid pressure to prevent blowouts

（井喷） . The density of the mud must be raised at times to stabilize inco mpetent formations. Any substance that is denser than water and that does not adversely affect other properties of the mud can be added to raise the density to some e xtent. Cost is important, but there are other practical restrictions on the material to be selected. The solubility of salts limits their range of usefulness, and there are other problems associated with the use of such systems. Various finely-g round solid materials, as listed in Tabel 6-3, have been used to successfully raise drilling mud density. Table 6-3 Materials Used to Increase the Density of Drilling Material

Pricipal Component

S pecific Gravity

Hardness Moh’s S cale

Galena

PbS

7.4-7.7

2.5-2.7

Hematitc

Fe2O 3

4-9-5.3

5.5-6.5

M agnetite

Fe3O 4

5.0-5.2

5.5-6.5

Iron Oxide(manufactured)

Fe2O 3

4-7

Lllmenite

FeO.TiO 2

4.5-5.1

5-6

Barite

BaSO 4

4.2-4.5

2.5-3.5

Siderite

FeCO 3

3.7-3.9

3.5-4

Celestitc

SrSO 4

3.7-3.9

3-3.5

Dolomite

CaCO 3. M gCO 3

2.8-2.9

3.5-4

Calcite

CaCO 3

2.6-2.8

3

Obviously, the specific grav ity of the weighting agent is of primary importance, especially in very heavy muds. The fractional volume（ 体积函数） occupied by the added solid is a major limiting factor in its use. Figure 6-1 shows the effect of the specific gravity of the weighting material on the solids concentration of weighted muds（加重泥浆）. For examp le, the solid content of mud weighted to 19.0 lb/gal (2.28 g/cm3 ) with material having a specific gravity of 4.2 is 39.5% by volume, as compared with 30% by volu me for a material of 5.2 specific grav ity.

94

Several factors in addition to chemical inertness（化学惰性） and specific gravity affect the use of a substance as a weighting material. First, the substance should be available in large quantities. It should be easily ground

to

the

preferred

particle-size

distribution （ 粒 径 分 布 ） , and relatively nonabrasive （磨损性小） , it should also be moderate in cost, and not injurious or objectionable to the drilling crew or the surroundings. Consideration of these factors, along with chemical inertness and specific gravity, has made barite the only mineral now used in significant quantities in the Un ited States to raise the density of muds.

6.3.1 Barite（重晶石） 6.3.1.1 Characteristics(特性) Pu re

barite

(bariu m sulfate,

BaSO4 )

contains 58.8% bariu m and has a specific gravity of 4.5. Co mmercial barite, somet imes called "heavy spar" or "tiff," is of lower specific gravity because other minerals (such

Fig. 6-1 Effect of specific gravity of weighting material on the solids concentration of weighted muds

as quartz, chert 燧石 , 黑硅石 , calcite, anhydrite, celestite 天青石，锶矿石 , and various silicates) are included. In addit ion, it usually contains several iron minerals, some of which may increase the average specific gravity of the product. Barite is virtually insoluble in water, and does not react with other components of the mud. Calciu m sulfate, sometimes present as gypsum（石膏） or anhydrite associated with barite, is objectionable as a contaminant of lightly-treated, fresh water muds. Sulfide minerals, such as pyrite（黄铁矿） and sphalerite（闪锌矿） , if present, may undergo oxidation with the format ion of soluble salts that adversely affect the mud performance. The dark-gray-to-black barite produced fro m mines in Arkansas, California and Nevada contains a small amount of organic matter and gives off the odor of hydrogen sulfide（硫化氢） when the ore is broken, but the odor does not persist in the finished product. Barite occurs in many geological environments in sedimentary, igneous and metamo rphic rock. Co mmercial deposits of barite occur as vein or cavity-filling deposits, residual deposits, and bedded deposits.Barite that meets API specificat ions must meet the requirements listed in Table 6-4. Table 6-4 Barite Reqnirements for API S pecification Specific gravity: 4.20, minimum Wet screen analysis: Residue on U.S. Sieve (ASTM ) no. 200: 3.0% maximum Residue on U.S. Sieve (ASTM ) no. 325: 5.0% minimum Soluble alkaline earth metals as calcium: 250 ppm, maximum

95

6.3.1.2 Barite in Drilling Mud(钻井泥浆用重晶石) The quantity of barite required to raise the density of a given volu me of mud a specific amount can be readily calculated fro m the relation. V f  V0  VB M f  M0  MB

 f V f  0V0   BVB

f

where, Vf , Mf and and

0

are volu me, mass and density of the drilling fluid weighted by barite; V 0 , M0

are volu me, mass and density of drilling fluid to be weighted; VB , Mf and

 f are

volume,

mass and density of barite to be added. When there is no limitation to the final fluid volu me, then, Vf 

 B  0  V0 B   f

6-1

M B  (V f  V0 )   B

6-2

Example 6-1: Using API Barite to increase 200m 3 drilling fluids of 1.32g/cm 3 to 1.38 g/cm 3, there is no limitation to the final fluid volume, try to calculate the final volume and the needed barite quantity. Solution:

 B =4.2 g/cm3, then from equation 6-1 and 6-2, then, Vf 

 B  0 4.2  1.32  V0   200  204 .255 m3 B   f 4.2  1.38

M B  (V f  V0 )   B  (204 .255  200 )  4.2  17.871T  17871 kg

When there is limitation to the final fluid volu me because of certain volume mud p it, some original fluid shall be disposed before adding barite, then, V0 shall be calcu lated as follows, V0 

 B  2 Vf  B  1

6-3

Example 6-2, Using API Barite to increase 200m 3 drilling fluids of 1.32g/cm 3 to 1.38 g/cm 3, there is limitation to the final fluid volume, namely, no more than 200 m 3 final fluid volume, try to calculate the disposal volume Vdis of drilling fluid and the needed barite quantity. Solution:

 B =4.2 g/cm3, then from equation 6-3 V0 will be: V0 

B   f 4.2  1.38 Vf   200  195 .833m3  B  0 4.2  1.32

Vdis =200-195.833=4.167m 3

M B  (V f  V0 )   B  (200  195 .833)  4.2  17.5T  17500 kg When using water to dilute the original fluid to reduce the solid content for low-solid muds before adding barite, assuming the solid fraction fsf in the final flu id and fs0 in the original flu id, then, V f  V0  VW  VB

 f V f  0V0  W VW   BV B f sf V f  f s 0V0

Then,

 f  V0  V f  sf   f s0 

6-4

96

VW 

(  B   f )  V f  (  B  0 )  V0

 B  W

M B  (V f  V0  VW )   B

6-5

6-6

Example 6-3: Using API Barite to increase 159m3 drilling fluids of 1.14g/cm3 to 1.68g/cm 3, and the final fluid volume is 127m 3, solid fraction shall be decreased from 0.05 to 0.03, try to calculate the disposal volume Vdis of drilling fluid, the added water volume and the needed barite quantity. Solution:

 B =4.2 g/cm3, then from equation 6-4, 6-5, 6-6:  f  0.03 V0  V f  sf   127 ( )  76.2m3 f 0 . 05  s0 

VW 

(  B   f )  V f  (  B  0 )  V0

 B  W



(4.2  1.68)127  (4.2  1.14)76.2  27.15m3 (4.2  1.0)

M B  (V f  V0  VW )   B  (127  76.2  27.15)  4.2  99.330T  99330 kg

6.3.2 Iron Minerals(铁矿粉) Iron oxi des. Natural iron o xides of specific gravity 4.9-5.3(p rincipally hematite(赤铁矿 ,铁矿粉 ), Fe2 O3 ) were among the first materials used to increase the density of muds . In Germany, an iron o xide weighting material is made fro m the residue of pyrite roasting process for sulfuric acid manufacture. The residue is quenched(淬火 ), neutralized(压制 ), leached（沥滤 , and dried（干燥）. The product is classified to a particle size below 75 microns and to a part icle size distribution such that not more than 50% is below 10 microns. Advantages claimed for the product include: specific grav ity of 4.7; low abrasion and low magnetic susceptibility co mpared to natural iron ores ; 85% soluble in hydrochloric acid: and reactive to hydrogen sulfide with the formation of noncorrosive, insoluble iron polysulfides.

6.3.3 Calcium Carbonate(碳酸钙) Calciu m carbonate was proposed as a weighting material because the filter cake that forms on the productive format ion can be removed by treatment with hydrochloric acid. Calciu m carbonate is readily available as ground limestone(石灰石 )or oyster shell(贝壳 ). Calciu m carbonate is dispersed in oil muds more readily than is barite. Its low specific grav ity (2.6 to 2.8) limits the maximu m density of the mud to about 12 lb/gal (1.4 g/cm3 ). Shell flour or ground limestone is frequently used in workover muds(修井液 ).

6.3.4 Galena（方铅矿） Galena, PbS, with a specific gravity of 7.4 to 7.7, is used only in preparation of the extremely heavy muds sometimes needed to control abnormally high pressures . Galena is expensive; consequently, barite is used with it in p reparing muds to a density of about 30 lb/gal (3.6 g/cm3 ). Mud having a density of 32 lb/gal (3.8 g/cm3 ) can be prepared with galena alone as the weighting material. About 1,200 lb of galena is needed to make one barrel (3400 kg/ m3 ) of such mud. Galena is not a normal component of weighted muds. A supply of galena is maintained in the Gu lf Coast area for use in an emergency.

97

6.4 Inorganic Chemical Additives(无机处理剂) 6.4.1 Sodium carbonate(碳酸钠) Sodi um car bonate, Na2 CO3, soda ash, washing soda; white, hygroscopic powder (fine powder is called light ash; coarse dense ash), with density of 2.5 g/cm3 , soluble in water and reaching the h ighest degree of solubility about 34% at temperature of 36℃. Produced fro m deposits of trona(天然碱，碳酸

钠石 ) (Na2 CO3 NaHCO3 .2H2 O), fro m natural brines, and by the Solvay process. Principal use is for removal of soluble calciu m salts fro m makeup waters and muds: some use in clay beneficiation. Concentration: 0.2 to 4 lb/bbl (0.6 to 11 kg/ m3 ). Sodiu m carbonate ionizes(电离) and hydrol yzes(水解) easily in water, producing ions of Na +, CO3 2-, HCO3 - and OH-, the reaction happens as follows:

Na2CO3  2 Na   CO32 CO32  H 2O  HCO3  OH  Sodiu m carbonate turns Ca-Bentonite to Na-Bentonite through cation exchange(阳离子交换) and preci pitation(沉淀), namely clay beneficiation(粘土改性 ), i.e.:

Ca  Bentonite  Na2CO3  Na  Bentonite  CaCO3  Sodiu m carbonate can be used when the muds are invaded by Ca 2+ by precipitation,

Ca 2  Na2CO3  2 Na   C a C O 3 

6.4.2 Sodium hydroxide Sodi um hydroxi de, NaOH, caustic soda, lye; white; deliquescent(溶解 ) with density of 2.0-2.2 g/cm3 ; beads pellets, flakes. Strong irritant to tissues. Toxic. Produced by electrolysis of sodium chloride. Used in water muds to raise pH; to solubilize lignite(褐煤 ), lignosulfonate（木质素磺酸盐） and tannin（单宁） substances; to counteract corrosion, and to neutralize hydrogen sulfide（氢化硫）. Concentration: 0.2 to 4 lb/bbl (0.6 to 11 kg/ m3 ).

6.4.3 Calcium oxide and Calcium hydroxide(氧化钙和氢氧化钙) Calcium oxi de, CaO, unslaked lime, quick lime; white powder, solubility degree of 0.16% in water. Produced by roasting calciu m carbonate (limestone, oyster shells), and contains impurit ies present in the source material. Evolves heat on slaking to form hydrated lime. Strong irritant. Used in oil muds for the formation of calcium soaps（钙皂） and removal of water. Main ly used as slaked lime in water muds. Calcium hydroxi de, Ca(OH)2 , hydrated lime, slaked lime; soft wh ite crystalline powder. Produced by adding calciu m o xide to water, filtering, drying. Avoid inhalation of powder. Skin irritant, pH of solution is 12.4. Used in lime muds（石灰泥浆） , high-calcium-ion muds, and for the removal of soluble carbonates. Concentration: 0.5 to 20 lb/bbl (1 to 57 kg/m3 ).

6.4.4 Calcium sulfate(硫酸钙) Calcium sulfate, CaSO4 , anhydrite （无水石膏） , CaSO4 .

1 H2 O, plaster of Paris, gyp plaster; 2

CaSO4 .2H2 O, gypsum（熟石膏） , white of colorless crystals or powder with 2.31-2.32 g/cm3 density.

98

Slightly soluble in water with about 0.2% solubility. Obtained fro m naturally occurring deposits; also as by product. Non to xic. Source of calciu m ions in gyp muds. Concentration 2 to 8 lb/ bbl (6 to 23 kg/m3 ).

6.4.5 Calcium chloride(氯化钙) Calcium chl ori de, CaCl 2 , CaCl2 .H2 O, CaC12 .2H2 O, CaCl2 .6H2 O; white deliquescent crystals (75% solubility), granules, lu mps, flakes with 1.68g/cm3 density. Produced as a by-product of the Solvay soda and other processes, and also mined. Used in hole-stabilizing oil muds; in calcium-treated muds, in the preparation of dense salt solutions for co mplet ion and workover, and for lowering the freezing point of water muds. Concentration ranges fro m 10 to 200 lb/bbl (28 to 570 kg/ m3 ).

6.4.6 Sodium chloride(氯化钠) Sodi um chl ori de, NaCl, table salt, halite(岩盐 ), rock salt; white crystals with 2.20 g/cm3 density. Produced by evaporation of brines and by dry min ing. Used as produced or as prepared brine in completion（完井液） and workover（修井液） operations; to saturate water before drilling rock salt; to lower freezing point of mud; to raise the density (as a suspended solid) and act as a bridging agent in saturated solutions, and in hole-stabilizing oil muds. Concentration 10 to 25 lb/bbl (30 to 360 kg/ m3 ).

6.4.7 Potassium chloride(氯化钾) Potassium chl ori de, KCl, sylvite(钾盐 ), potash（苛性钾） ; colorless or white crystals with 1.98 g/cm3 density. Mined; purified by recrystallization. Sold in various grades based on K 2 O content. Shale inhibitor（页岩抑制剂）. Primary source of potassium ions for potassium-polymer muds(钾盐聚合物

泥浆 ). Concentration 2 to 60 lb/bbl (6 to 170 kg/ m3 ).

6.4.8 Sodium dichromate(重铬酸钠) Sodi um dichromate, Na2 Cr2 O7 .2H2 O; red-orange crystals with 2.35 g/cm3 density. Toxic by ingestion（摄取） or inhalation（吸入）; strong irritant. Prepared fro m chro mite ores; sulfuric acid on sodium chro mate. The dichro mate beco mes chromate in alkaline solutions; consequently, in muds the uses are the same. Used as constituent of chrome lignosulfonate（木素磺算铬） and chrome lignite compositions for increased thermal stability, and to inhibit corrosion in salty muds. Concentration 0.1 to 2lb/bbl (0.3 to 6 kg/m3 ).

Fig.6-2 Schematic representation of a polyphosphate molecule adsorbed on clay crystal edge by bonding with exposed aluminum atoms

6.4.9 Sodium polyphosphates and Sodium hexametaphosphate（聚磷酸钠和六偏磷酸钠） The sodium polyphos phates（聚磷酸钠） are very effective deflocculants（ 抗絮凝剂） for clays in fresh water and were among the first thinners for mud. They are not effective in salty muds (>10,000ppm ch loride). The glassy polyphosphates effectively soften hard water by forming soluble complexes（可溶性络合物） with calciu m and magnesium ions. This action, called sequestration（螯

合作用）, is applied in d ispersing bentonite for filtration reduction（降失水）. The reversion(反转 ) of 99

the polyphosphates to orthophosphates（正磷酸盐） , which may cause thickening of the mud, occurs rapidly as the temperature approaches the boiling point of water. This reversion limits the use of polyphosphates to relatively shallow drilling. Another factor that has caused a marked decrease in the use of polyphosphates in shale drilling is their tendency to promote disintegration and dispersion of shale cuttings, thereby increasing the solid content of the mud. Three products are now being sold as thinners: sodium acid pyrophosphate（焦磷酸钠）, sodium tetraphosphate（四磷酸钠）, and sodium hexa-metaphosphate（六偏磷酸钠） . Sodium aci d pyrophos phate（焦磷酸钠）, SAPP, Na2 H2 P2 O7 , can be made by heating sodium dihydrogen orthophosphate (thus, 2NaH2 PO4 →Na2 H2 P2 O7 + H2 O). A solution of SAPP has a pH of about 4.2 and consequently is effective in overco ming cement contamination of fresh water muds. Sodium tetraphos phate（四磷酸钠）, Na6 P4 O13 , can be made fro m the orthophosphates by heating (2Na2 HPO4 + 2NaH2 PO4 →Na6 P4 O13 + 3H2 O) or by the reaction of soda ash and phosphoric acid, in the ratio of 3Na2 O/ 2P2 O5 , and rap idly cooling the melt. Sodiu m tetraphosphate is the most frequently used polyphosphate. Its solution has a pH of about 7.5. Sodi um hexametaphosphate（ 六偏硫酸钠）, (NaPO3 )6 , is a glass, not a definite co mpound, having the ratio of approximately 1 Na2 O/ 1 P2 O5 . It can be prepared by fusion and rapid cooling of the melt (NaH2 PO4 →NaPO3 + H2 O). Its solution has a pH of about 7. The sodium polyphosphates are normally used in concentrations of 0.l to 1 lb/bbl (0.3 to 3 kg/ m3 ).

6.5 Polymers(聚合物) The use of polymers in drilling fluids first began in 1937, when corn starch was added to a bentonite mud to control the filtration characteristics. This development was followed fairly rapidly by the introduction of carboxy methyl cellulose, tannins, quebracho and lignosulphonates, all of which were in regular use by 1945. The initial use was to extend the properties of a simple clay based system and to protect the bentonite from salt flocculation. The materials used either occurred naturally, or could be extracted by simple processes. Since that time, the polymers used have become more sophisticated, and are often specifically designed for a particular drilling situation, even to the extent where clays are entirely replaced by polymers in such cases as drilling water sensitive shales or water production zones. The range and versatility of polymers is continually being extended, and it is the ability to tailor make a polymer with particular properties to suit a specific purpose that will ensure that polymers will solve drilling problems in the future. It is because polymers are fundamental to the control of the fluid properties that this section will deal in some detail with the structures of different polymers and attempt to relate the structure to the function as much as possible, so that the role and application of the particular polymers should then be better appreciated and understood. 6.5.1 Fundamental Structure of Polymers(聚合物基本结构) Basically, a polymer consists of a basic unit (monomer)(单体), or units, that are chemically joined together (polymerised) to form a chain. The units may be identical or radically different. The groups may also be chemically altered after they have been polymerized(Fig. 6-3).

100

Fig.6-3.Fundamental polymer structure

From this simple picture a number of possible variations can be visualised. Some are listed below: A. Type of monomer or monomers. B. Number of monomers joined together to form a chain --i.e. molecular weight. C. D.

Number of cross linking or branching groups in the chain. Type and extent of subsequent chemical modification.

The factors that determine the behaviour of a particular polymer are quite complex and often only relatively small changes in the structure of the molecule can substantially alter its properties. This gives the polymers an inherent versatility, which is reflected in the wide variety of applications for which polymers are suited. The most important structural variables are: Molecular weight or chain length(分 子 量 或 链 长 ). This can be varied by limiting the number of chain terminating groups, or by chemically degrading longer chains. Another important feature is the distribution of molecular weights. This is illustrated in Figure 6-4 for two samples with the same mean average molecular weight. In the case where there is a broad size distribution, the larger quantities of lower molecular weight material may dominate, or at least modify, the reaction of the higher molecular weight materials.

Fig.6-4 Different molecular weight distribution curves

101

Type of reactive groups(反应基团类型). The chemical reactivity is mainly dependent on the type of groups that are attached to the molecule and the number of groups. There is often more than one type of reactive group. The distribution of the groups on the polymer backbone will also affect the properties and reactivity. Often, because of the complex nature of the polymers, the details of the structure are not known, but different reaction conditions can produce differences in structure that can influence the performance of the polymer. The groups that can be attached onto the polymer can be divided into three groups: A. non-ionic(非离子) B. anionic or negatively charged(阴离子或负电性) C. cationic or positively charged(阳离子或正电性) More than one type of group may be present in the molecule. The types of groups are given in Table 6-5. The charge nature of some of the groups is dependent on the pH of the system and will change from non-ionic to cationic or anionic because the groups are weakly basic or acidic respectively. Table 6-5

Polar Groups(极性基团)

Class

Non-ionic

Anionic

Cationic

Group Name

Formula

hydroxyl

—OH

ether linkage

R—O—R

ester

—O—CH 3

phenolic OH

C6H5OH→C6H5O-

carboxyl

COOH→COO -

—sulphonic

—SO 3 H→—SO 3-

—phosphate

—PO 3H→—PO 3-

—amine

—NH 3→—NH 4+

Three dimensional structure. The eventual shape or three dimensional structure of the molecule will depend on the following factors: A. B.

branching or cross-linking in the structure the concentration and type of groups on the molecules

C.

the pH of the solution as it changes the ionic character of the molecule and therefore the degrees of repulsion and attraction within the molecule The ionic strength(离 子 浓 度 ), or salt concentration( 盐 浓 度 ), as this affects the

D.

electrostatic repulsion between the charges. This topic was discussed in some detail in the clay chemistry section, where it was shown that an increased level of electrolyte changed the balance between the repulsive and attractive forces and allowed like-charges to approach each other more closely. The effect on a negatively charged polymer is to change the configuration from an extended polymer in fresh water, where charge repulsions are stretching the molecule, to a tightly-coiled structure in a saline solution, where the repulsive forces are lower. This is shown diagrammatically in Figure 6-5.

102

Fig. 6-5 Effect of electrolyte concentration on polymer configuration

The change in molecular shape will change the physical properties of the polymer in solution. It can be visualised that the coiled up polymer will present less interaction surface to the water or to other polymer molecules. Since it is these reactions that develop viscous properties, it can be seen that increased salt will decrease the viscosity of a charged polymer. Conversely, the viscous properties of a non-ionic polymer should be essentially unaltered by salt. E.

Multivalent ions(多元化合价离子) can act as bridging agents by reacting or complexing with more than one charged group on the molecule. The bridging can reduce the solubility and viscosity and is the reason why cement, which supplies soluble calcium ions and a high alkalinity, can react with anionic polymers such as CMC's. The extent of the reaction is a function of the concentration of the multivalent ions and the pH of the solution.

This section has developed in general terms, the structural features of polymers and how different features in the structure will give different properties. The next section will develop these concepts more fully with specific polymers. 6.5.2 Relationship between Polymer Structure and Function in Drilling Fluids (聚合物结构与 功能的关系) This section will show the general features required of a polymer to perform a particular function in a drilling fluid. The next section will then describe the polymers that meet these criteria and others, such as cost, availability and stability in a mud system. Table 6-6 summarises the relationships between function in a drilling fluid and the essential features of the structure of the polymer. Table 6-6 Summary of Relationship between function of a polymer in a drilling fluid and its general structure Function

Main characteristics

Viscosity

High molecular weight

Viscosity and gellation properties

High molecular weight and highly branched structure or cross linking agent

Viscosity in salt solutions

High molecular weight and non-ionic or highly substituted anionic types

Deflocculation, dispersion or thinning

Low molecular weight negatively charged at alkaline pH values

action Flocculation

High molecular weight with charged groups to adsorb onto clays

Surfactant

Hydrophobic group and hydrophylic group on same molecule

Fluid loss additive

Form colloidal particles

Viscosity(粘度). The viscous properties that are conferred to water by the solution of a polymer are due to the interactions of the water with the polymer and polymer polymer interactions. The longer the molecules, the harder it is to separate the molecules from each other and the more tangled they become. Figure 6-6 gives the relationship between concentration and viscosity for two polymers of different molecular weights. The viscosity is due to interactions between the polymer molecules and water, between the polymers themselves and between the polymers and solids when these are present. These forces giving rise to the viscosity can be disrupted by supplying energy or shear. The result of this is that 103

the greater the shear rate, the lower the viscosity becomes. Solutions that exhibit this behaviour are called pseudoplastic or shear thinning fluids(假塑性或剪切稀释流体). This is ideal flow behaviour for drilling fluids, because low viscosity is required at the high shear rate zone near the bit and higher viscosities are needed in the lower shear rates in the annulus, to transport cuttings to the surface. It will be seen from Figure 6-6, that the same viscosity can be derived from a small concentration of high molecular weight material as from a larger concentration of low molecular weight material. Since the cost of the two polymers on a weight basis is essentially identical, it is more cost effective to supply the high viscosity derivative. Quite separate from the shear thinning rheological behaviour is the problem of mechanical or chemical degradation of the polymer chain, to form a lower molecular weight derivative with the lower viscosity characteristics. Thus, conditions of high mechanical shear, such as mechanical pumps and extrusion through nozzles, can cause a decrease in viscosity. Linear molecules, such as those derived from cellulose, tend to be more susceptible to

Fig.6-6 Effect of concentration on viscosity of a high and low molecular weight water soluble polymer

mechanical degradation, than highly branched polymers, such as bacterial polysaccharides. Conditions of high temperature, high oxygen levels and high alkalinity would tend to make most organic polymers more susceptible to chemical degradation. As discussed earlier, salt has the effect of reducing the repuls ion of charged sites within the molecule, which will produce a contraction of the polymer with a consequential loss in viscosity. This effect may cause the polymer to be half as effective. The effect may be minimised if the polymer if allowed to hydrate in fresh water initially. Obvious ly, this effect will be minimal for non-ionic molecules. The solubility and molecular dimens ions can be altered by reaction with multivalent ions, such as the reaction between CMC's and calcium. The stability of these anionic polymers to multivalent cations is quite complicated and depends upon the cations present, concentrations, and the pH of the solution. Generally the combination of high pH and high alkalinity tends to make the system less stable due to the precipitation of metal hydroxide - polymer complexes. Deflocculants(解絮凝剂). The deflocculants, or thinners, in alkaline clay based systems, usually achieve the results by adsorption of the negatively charged polymer onto the clay platelets, thus neutralising positive charges and creating an overall negative charge. This is illustrated in Figure 6-7. Thus, the thinners are characterised by being negatively charged and low molecular weight. If the polymer is too long, it will bridge between particles and exhibit a flocculating action. The types of materials that fit this molecular description will be discussed in the next section. Flocculants(絮凝剂). Flocculants are characterised mainly by a high molecular weight which will enable the polymer to bridge from particle to particle. Molecules with ionic groups can

104

adsorb more strongly to ionic sites and thus flocculate more effectively. Figure 6-7 attempts to show how a polymer, with the same reactive groups, can act as a deflocculant at low molecular weight and as a flocculant at high molecular weight.

Fig.6-7 Diagram to illustrate low M .W. polymers acting as deflocculant and high M .W. polymers act ing as flocculants

Surfactants(表面活性剂). Surfactants are polymers in which each molecule contains two assemblies of atoms or groups. One group is polar and thus attracted to a polar surface, such as water, and is called the hydrophylic, or water-loving group. The other group is a non-polar, hydrophobic or water-hating group. The nature of the surfactant is related to the type of hydrophobic and hydrophilic group and the combination of groups. When the groups are polymeric a whole family of molecules can be produced with the balance of hydrophobic and hydrophylic groups gradually changing over the series. Table 6-7 lists some of the groups that can be combined to make a surfactant. Table 6-7 S ome of the non-polar and polar groups that may be incorporated into a surfactant molecule Non-polar group

Polar group

Hydrocarbon chain

hydroxyl -OH

CH 3-(CH2)

n-

often

derived

phenolic R.OH

fromnatural oils and fats or from

Ether -CH 2-CH 2-O-CH2CH2OH

petroleum.

Carboxylic - R-COO -

M ay

contain

unsaturated bonds in molecule

Ester-R-COOR1

-CH = CH-

Sulphonate-OSO 3Sulphate–SO 3Sulphosuccinate CH 2 COOR -O3S-CH COOR Amine -R-NH 2 105

The particular property of surfactants that is utilised in drilling fluids, is the ability of these molecules to exist at the interface of hydrophobic and hydrophylic surfaces. The molecule bridging these surfaces lowers the energy of the system and makes it stable. For example, oil would not, by itself, form a stable system of oil droplets within water. Mechanical energy would have to be put into the system to make the small drops, but they would separate out, given time, into two phases again. However, the introduction of a surfactant that migrates to the oil water interface, will stabilise the system. The nature of the surfactant will decide whether the system contains oil droplets within a continuous water phase--a direct emulsion, or water droplets within a continuous oil phase an invert emulsion. Water soluble surfactants, with a relatively large polar group, tend to give direct emulsions, and oil soluble surfactants, with relatively large non-polar groups are used to form invert emulsions. These oils and lubricants are incorporated into some systems up to about 20% to form direct emulsions. These oil emuls ions have a characteristic white milky appearance. Invert emulsions are used where the rocks need to be kept oil wet, for example when water sensitive rocks are being drilled, or when water will impair the productivity of oil bearing rocks. Table 6-8 lists some other interfaces that require modification with a surfactant Interface Function of surfactant Non-Polar

Polar

oil

water

emulsifier - direct or invert

air

water

foamer or defoamer

steel

water

Lubricant, corrosion inhibitor

steel

clay

detergent

clay

water

dispersant

oil

clay

oil wetting agent

Fluids loss additives(降滤失剂). Polymeric additives can affect the fluid loss by essentially three different mechanisms. A deflocculated filter cake will pack down to form a thinner, more impermeable filter cake, so that polymers that act as deflocculants, such as low viscosity CMC or lingosulphonates, will lower the fluid loss. If the liquid phase that is being forced through the filter cake is viscous, this will lower the fluid loss also. Examples of these polymers are high molecular weight CMC or xanthan gums. These two mechanisms are secondary functions of two polymer types, namely deflocculants or viscosifiers. A third mechanism of lowering fluid loss is to add colloidal particles that can compress and deform to plug the pores in the filter cake. The structures of starch, some asphalt derivatives and lignin derivatives fit this description.

6.5.4 Polymers used in drilling fluids(钻井液常用聚合物) This section will describe the structures of some polymers used in drilling fluids and relate the structure to the application, so that the use of polymers in drilling fluids is understood. A commercially available material may be a blend of materials, because of an overlap of properties and because of synergistic effects. Also, although a product is referred to as a generic type, there are subtle differences between these polymers, dependent on factors, such as the 106

manufacturing process and raw materials. These can make substantial differences to the performance of the drilling fluid. Some of the products and functions are summarised in Table 6-9. Table 6-9 Types and functions of Polymers in drilling fluids Polymer Type

Description

Examples

Carboxymethyl

Polysaccharide

cellulose ether

anionic-COO- groups

CM C

High molecular wt

High viscosity CM C

Viscosifier, fluid loss additive

Low molecular wt

Low viscosity CMC

Fluid loss

HEC

Viscosifier-particularly

Hydroxyethyl

Polysaccharide

cellulose ether

non-ionic

HEC

molecular weight

Starch

Polysaccharide

linear

Functions

polymer

linear

ether

polymer

group

highly

gums

polysaccharide

brines.

Corn. potatoes, tapioca,

Fluid loss control in salt

forms colloidal solution normally

etc. Various ly chemically

solutions

-

modified

Polysaccharide branched complex structure some anionic

Xanthan gums

Viscosifier-particularly in salt

groups.

water and where suspension

High molecular weight

properties are required

gums

Polysaccharide branched – high

from trees and

molecular weight some anionic

shrubs

groups complex structure

Lignosulphonate

Natural

for

branched

non-ionic or anionic-COO Bacterial

high

additive

Guar, Gum arabic

Viscosifier

Water soluble sulphonate derivative

Calcium lignosulphonate

Thinner

of lignin - range of metal salts

Calcium-chrome

deflocculant

lignosulphonate

fluid loss control

Ferro-chrome lignosulphonate M ined lignins

M etal salts of petrified humic acid

Chrome lignite,

Water loss control and thinner

Potassium lignite, Causticized lignite Tannin

Extracts from bark and wood

Quebracho

Polyphosphates

M olecularly dehydrated phosphates

Sodium

Thinner acid

Thinner

pyrophosphate Vinyl polymer

Polymer

of

acrylic

acid

CH2=CHCOOH

-CH2 -CH-CH 2-CH-

Low molecular weight <1,000

C=O

C=O

thinner.

O-Na

O-Na

High

molecular

weight

flocculant Vinly polymer

Co-polymer of acrylic acid and acrylamide in various ratios

Co-polymer

Vinyl

acetate-maleic

anhydride,

high molecular weight

-CH 2 -CH-CH 2-CH C=O

C=O

O-Na+

NH 2

-CH 2 -CH-CH-CHCO CO

Flocculant shale stablizer

Flocculant bentonite extender

CO

O=CCH 3 OH OH Surfactants

Resin soaps calcium soap of tall oil lecithin

Synthetic polymers

Emulsifier for water in oil emulsifier for oil in water

107

Nonylphenolethoxylate

alkyl

drilling detergent

sulphonates Surfactants

n-Tridecyl

polyoxy

ethylene

Synthetic polymers

Foaming agent

sulphated

Synthetic polymers

Defoamer

Fatty acid glycerides, ethoxylated

Synthetic polymers

Lubricant corrosion inhibtor

ethanol, nonyl phenol polyethylene glycol ether Surfactant

Higher

alcohols,

vegetable oils Surfactants

long chain alkyldiamine

The polysaccharide(多糖) class of polymers is the most widely used group of polymers used in drilling fiuids, and includes the cellulose derivatives, starches, bacterial polysaccharides, and gums. The basic unit(基本单元) is glucose（葡萄糖）, which contains only carbon, hydrogen and oxygen atoms. Figure 6-8 gives a three dimensional diagram of the cyclic molecule. The polymers are constructed through an oxygen atom connecting carbon atoms of another glucose unit to form a glucosidic linkage, as shown in Figure 6-9. This linkage can be formed between hydroxyl groups on C-1, C-2 and C-6. The linkage on C-1 can be either below the ring shown in Figure 4/6 (an alpha, α linkage), or above the ring (a beta, β-linkage). An extens ive range of polymers can be manufactured by modifying natural products. They will all contain the same monomer group, but will differ in molecular weight, type of

Figure 6-8 Glucose showing three dimensional structure and numbering of carbon atoms

linkage and chemical modification. The different structures can be related to the different functions of the molecules.

Figure 6-9 Glucosidic link between glucose units

Cellulose Derivatives. Cellulose is composed of glucose units joined by β-(1→4) linkages, which gives the linear polymer shown in Figure 6-10. Wood fibre consists of bundles of these molecules, cross-linked with a material called lignin(木质素). Cellulose is insoluble in water, but it can be chemically modified to introduce more hydrophylic groups and to break down the crystalline structure of the cellulose. The reaction is to swell the cellulose with alkali and then form chemical derivatives of the hydroxyl groups on the anhydrogtucose units.

108

Figure 6-10 Structure of cellulose

Carboxymethyl Cellulose (CMC). In the case of CMC, a carboxymethyt group (-CH2 COOH) is attached to a carbon atom via an ether linkage, as shown in Figure 6-11. The cellulose is first reacted with sodium hydroxide to form the alkali cellulose and then with monochloro acetate. There are potentially three reactive hydroxyl groups. The extent of the reaction is referred to as the degree of substitution(取代 度), or DS, which is normally in the range 0.8-1.2 for CMC's used in drilling fluids. The uniformity of substitution can also modify the properties. The more uniform the distribution, the smoother and less thixotropic, or shear thinning, the solutions will be. A third variable is the chain length, or degree of polymerization(聚合度), which can be altered by chemically or mechanically breaking the glycosidic bond.

Fig.

6-11

Stucture

of

caboxymethyl cellulose

Thus, it can be seen that a low molecular weight CMC will exhibit the characteristics required for a deflocculant, namely low molecular weight and negative charge. A high molecular weight CMC will be used as a viscosifier and also possess some fluid loss properties. This group of polymers have been used extensively in drilling fluids because of the features of moderate cost and stability to both salt and moderately high temperatures. Hydroxyethyl Cellulose (HEC).

The production process for making HEC is based on the

reaction between alkali cellulose and ethylene oxide as follows. O R-OH+NaOH→R-ONa+CH2 -CH2 →R-OCH2 CH2 OH Subsequent reactions can take place on the ethylene oxide. An idealised unit structure is given in Figure 6-12. Control of reaction conditions can produce different polymers by effecting the four main variables:

Fig.6-12 Structure of hydroxyethyl cellulose A. B.

length of cellulose chain. degree of substitution (DS) on the cellulose unit normally 1.5-2.5 DS for a water soluble

C.

polymer. degree of polymersation of the polyethylene side chains called the molar substitution

109

(MS). D.

uniformity of substitution.

The polymer does not contain any ionic groups and therefore is ideally suited as a viscosifier for completion fluids and other brine based fluids. The polymer exhibits highly developed thioxotropy or shear thinning characteristics but does not exhibit any yield stress or gellation properties. The material may be specially treated to improve its solubility in water. Other cellulose derivatives may also be prepared with both the CMC and HEC groups on the one molecule, or be prepared with other groups. Starch. Starch is present in plants as a form of food storage. Starch grains possess a hard outer cell wall made from a polysaccharide called amylopectin. The structure is given in Figure 6-13. Inside the shell are bundles of a linear, coiled polysaccharide, called amylose. The structure is given in Figure 6-14.

Fig.6-13. Structure of amylopectin (a) showing branching (b) chemical structure of α-D (1→6) link

Fig.6-14 Structure of amylase(a) chemical structure (b) three dimensional structure(c) helical form of chain

For the starch to exhibit fluid loss control properties, the amylopectin outer shell has to be ruptured in a process known as pregelatinization, which releases the water-swellable amylose. This is shown diagrammatically in Figure 6-15. This product can then be further modified to decrease the viscosity and then be cross-linked to increase temperature stability. The properties of the starch can also be varied by the source of crude starch, which may be potato, or tapioca.

110

Fig.6-15 Schematic diagram of the manufacture of modified starches. (A) Starch grain(B) Pregelatinised starch(C) M odigication to reduce viscosity(D) M odification to increase temperature stability.

Thus, starch can be modified to form a very effective agent to lower fluid loss, particularly in flocculated salty fluids, by forming colloidal water-swellable particles that will seal pores in the filter cake. Microbial Polysaccharides--Xanthan Gum. Bacteria of the Xanthomonas genus can produce gummy colonies. These simple, single celled bacteria excrete a polysaccharide gum to form a protective layer to prevent dehydration and provide a physical barrier to attack by bacteriophages. They can be grown by aerobic fermentation on a simple medium that includes a carbohydrate source such as D-glucose, sugar, or hydrolysed starch. The bacteria are killed after the fermentation and the gum extracted and precipitated by isopropyl alcohol. After the alcohol is recovered, the gum is dried and milled. This purification process is very expensive. Xanthan gum is a heteropolysaccharide, with a molecular weight in excess of 1 million. The gum contains a basic repeating unit of 16 units. A probable structure is given in Figure 6-16. Note that it is a branched structure which contains polar carboxyl groups and ester groups the polymer forms viscous solutions that are highly pseudo-plastic or shear thinning, or low shear thickening. This well-developed behaviour is thought to be due to the formation of coiled structures that aggregate together strongly at low shear rates. The aggregation is so well developed that solutions have an apparent yield value. That is, stress has to be applied before the fluid flows. An important consequence of this is that xanthan polymer solutions have excellent suspension properties that cannot be matched by other polymers at equivalent concentrations. The polymers' viscous properties are generally not affected by salt or temperature.

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Fig.6-16 Probable structure of the repeating unit of xanthan gum showing complex branched structure

This polymer has particular application in low solids potassium based fluids and will increase the carrying capacity without increasing the viscosity greatly. The polymer also has application in completion fluids, where suspension of weighting material is required. Natural Gums—Guar. Guar gum is derived from the seed of the guar plant. It is a polysaccharide polymer with molecular weight of about 220.000. The repeating unit is composed of galactose(半乳糖) and manose. The probable structure is given in Figure 6-17.

Fig.6-17 Probable structure of repeating unit of guargum

The polymer may be chemically modified by reaction with the hydroxyl groups. The features of the structure of high molecular weight and non-ionic grouping ensure very high viscosities and an absence of sensitivity to salt. It may be used to build a viscous polymer fluid in large surface hole drilling. Lignins and Lignosulphonates(木质素和木素磺酸盐). Lignin is a major component of wood and binds the bundles of cellulose fibres together. To produce cellulose pulp for paper production, the lignin may be solubilised by reaction in hot alkali and bisulphite. The structure of

112

lignin is not known with any precision. A suggested possible structure for a lignin monomer is given in Figure 6-18, to indicate the types of reactive groups that are present. They may be condensed to carbohydrates. The structure is very complex and should not be regarded simply as a polymer of the repeating monomer unit. The bisulphite extraction process causes partial hydrolysis of the carbohydrate structure and the formation of sulphonic groups on the hydroxyl groups of the side chains. The lignosulphonic acids may be reacted with bases or salts to form acid salts such as sodium, calcium aluminium iron or chromium The acids can also form co-ordination compounds in which the hydroxyl (-OH), carboxyl (COOH) and carbonyl (C-O) groups in the molecule can form co-ordination compounds, or chelates with transition metal ions such as chromium. Such a reaction is illustrated in Figure 6-19 in which the lignosulphonate molecule is depicted as "LIG".

Fig.6-18 Probable structure of repeating unit of lignin

Fig. 6-19 M ain Structure of Ferrochrome Lignosulfonoate

The chrome lignosulphonate complex product contains a high number of hydrogen bonding groups, such as carbonyl (C=O) and carboxyl (COOH), through oxidation reaction and also increases the viscosity of the lignosulphonate solution by cross-linking. The lignosulphonate material in solution can be described as an association colloid. This consists of molecules of molecular weight in the range of 1,500 to 10,000, that exist in solution as rigid ellipsoids with a highly polar surface containing sulphonate, carboxyl, carbonyl, phenolic and hydroxyl groups. The molecule is strongly adsorbed onto clay surfaces and can effectively act as a deflocculant by neutralisation of positive charges, which will create an overall negative charge on the clay solids. Mined Lignins. Lignin is petrified humic acid. The chemical structure is virtually unknown, but it will probably contain aromatic groups and phenolic groups. A proportion may be soluble in alkali, which indicates the acidic nature of the material. It can be simply mined and processed at low cost.

113

It can be used as a thinning agent and the insoluble, or water-swellable components, will impart a level of fluid loss control. It may be supplied as the acidic material, ground with caustic soda to neutralise it (causticised Lignite). Tannin. Tannin is a water soluble, low molecular weight acidic material extracted from the bark and wood of trees. Extensive quantities are obtained from the quebracho tree, grown in Argentina. The material is extracted from the ground bark or wood with hot water under pressure. The water is then evaporated and the solid product milled often with fine clay or calcium carbonate, to prevent the material resolidifying. The structure is quite complex and varies in some details, dependent on the source of material. The postulated structure is based on a sub unit in which five molecules of digallic acid are reacted with one molecule of glucose. The acids are represented in Figure 6-20.

Fig.6-20 Tannic acids that esterify with glucose to form tannins

The acidic low molecular weight molecule is an effective deflocculant and is particularly effective in fluids with a pH above 11.5. The development of lower pH, gyp-lignosulphonate fluids superseded the tannins. Polyphosphates. The monomers, the orthophosphates, are polymerized by removal of water to form the metaphosphates and pyrophosphates. The meta and pyrophosphates are reacted with each other to form the polyphosphates. The fundamental unit is the trivalent phosphoric acid, which can be successively neutralised to form the three sodium members, mono, di and tri. The three stages are shown in Figure 6-21.

114

Fig.6-21 Dehydration of ortho phosphates to form polyphosphates

The commercial material may be a mixture of the phosphate polymers, or may be esters of tannin products or complexes with heavy metals. The low molecular weight, acidic molecule will act as an effective thinner, particularly in low pH, low temperature fresh water muds. The thinners are not effective in high calcium environments and could not be used in temperatures above 65℃ (150℉), because they would revert to the mono-phosphates. Synthetic polymers. A wide range of synthetic polymers are based on the polymerisation of molecules that can be described as substituted ethylene. They polymerise to form a carbon-carbon backbone in Figure 6-22.

Fig.6-22 Polymerisation of substituted ethylenes

The group on the substituted carbon can be varied or modified after polymerisation. Also the chain length can be varied by altering the reaction conditions. Polyacrylates. Materials with a molecular weight of less than 1,000 can be effective deflocculants and may have particular application at higher temperatures, because they possess greater resistance to thermal and bacterial degradation than the natural polymers, such as starch and CMC. The application is limited by the tendency to form insoluble salts with polyvalent ions. Co-polymers of acrylamidel acrylate. Hydrolysed polyacrylamide chains will contain

115

carboxy and amide groups. They can be prepared by polymerisation of the acrylamide and acrylate, or by hydrolysis of polyacrylamide. The molecular weight and ratio of acid toamide groups can be varied. High molecular weight polymers, with about 30% acid groups, have been shown to be effective as agents that stabilise water sensitive shales. They may be also used for flocculaets in clear water drilling fluids, where the molecular weight is in excess of 2 million and the carboxyl groups account for less than 10% of the groups. Intermediate molecular weight material (150,000-250,000) with 60-70% acid groups can be used for effective fluid loss control. Co-polymer of vinyl acetate and maleic anhydride. Co-polymers of vinyl acetate and maleic anhydride have shown particular application as bentonite extenders. Low levels (0.5% w/w of polymer on clay) can double the plastic viscosity of a 3-5% bentonite suspension. The polymer acts as a selective flocculant and is characterised by a high molecular weight and negative charges. Various other polymers in this general group may have specialised application, but will not be detailed here. Surfactants. The basic principles of surfactants are given in Figure 6-23. The products are often proprietary blends of a number of surfactants whose compositions are not disclosed. Limited examples and structures can be given. The main features are the hydrophobic balance within the molecule of the polar and non-polar groups and the polar nature of the groups.

Fig.6-23 Diagrammatic representation of a surfactant

Oil-in-water emulsifiers. Oil may be added purposely to a water based mud to lower the density, to increase the drilling rate and to improve hole stability. Oil may also enter the mud from producing formations, or be added to free pipe that has stuck. If the oil is emulsified, the performance will be improved and the fire hazard essentially eliminated. Lignitic material, lignosulphonates and tannins are effective, but specific surfactants, such as sulphonated hydrocarbons, sodium salts of tall oil or polyoxy-ethylene esters and ethers, may be added. The surfactants are dissolved in the water phase. Water- in-oil emulsifiers. Fluids are designed with a continuous oil phase, where the water is held in fine droplets by the action of surfactants. To stabilise a water-in-oil emuls ion, the surfacants are in the oil phase. Typical examples are calcium soaps and lecithin. Foaming agents. A surfactant is added to stabilize the foam formed, when water enters a well being drilled with air as the flushing medium. Typical examples are nonylphenol polyethylene

116

glycol ether and n-tridecylpoly-oxyethylene ethanol. Defoaming agents. Air, or other gases, may be entrained in the mud by the surface equipment or by high pressure gas from the formation. The release of this gas is facilitated by a defoaming agent. Examples include higher alcohols, sulphated vegetable oils and aluminium stearate. Mud detergents. Detergents have been found to decrease the tendency for the shale being drilled to adhere to the bit in a condition described as "bit balling‖. Often non-ionic detergents of the type described as oil in water surfactants are effective. Stuck pipe surfactants. Surfactants are added to break down a filter cake and oil wet the drill pipe. A blend of surfactants would be used. Refer to chapter on Stuck Pipe for more information. Lubricants. A surfactant can be added to specifically form a lubricating film between the drill string and the hole. This may be of the type used to emulsify water in oil, or it may be a specific additive, such as a fatty acid or ester. Corrosion inhibitor. A surface active agent can form a film on metal surfaces to isolate the metal surface from the corrosive environment. Chemicals, such as ethoxylated long chain alkyl diamines, may be used for this purpose. Refer to chapter on Corrosion for more information. Exercises: 1.

How the properties of drilling fluid can be affected by water?

2.

What kind of Bentonite shall be used for making up muds with high quality?

3.

Using API Barite to increase 180 m3 of drilling fluid the density fro m 1.10g/cm3 to 1.25g/cm3 , the final fluid volu me is 180 m3 , then calculate: 1) How much muds shall be disposed before weighting; 2) Ho w much barite shall be added?

4.

Exp lain the functions and mechanis ms of Sodiu m carbonate (Na2 CO3 ), Sodiu m hydro xide (NaOH), Calciu m chloride(CaCl2 ), Potassium chlo ride (KCl) and sodium polyphosphates .

5.

Expat iate the mechanism of NaT(Th inner) and CMC (Filtration reducer) by analyzing their structure separately.

6.

Write out the hydrolysis process of polyacrylonitrile(聚丙烯腈).

7.

Interpret the following concepts their functions: DS, DP, chelation(螯合作用), adsorption groups and hydration groups and.

117

CHPATER 7 WATER BASE DRILLING FLUID Water base muds are the most widely used of the three general types of drilling fluids. In most wells, a water base mud is used during the entire drilling operation. In many wells, where the primary drilling fluid is an oil or invert emulsion mud, or gas, only part of the drilling operation may be done with water base mud. Drilling muds vary widely in their composition and in the amount and type of chemical treatment they receive, owing to the need to provide the most economical mud for the type of well and the portion of the hole being drilled. In the following, the requirements for a satisfactory drilling fluid for different portions of the hole and for different drilling conditions are discussed separately. 7.1 Classification of Bentonite Drilling Fluid Systems(膨润土钻井液体系分类) Early drilling fluids were merely freshwater suspensions of drilled solids, or natural muds. In the 1920s, it was appreciated that the density of the fluid should be regulated to control subsurface formation pressures, and dense minerals, such as iron oxide and barite were added. The specific use of bentonite as a suspending agent for the weighting materials was introduced in 1929. This development was followed by the use of thinners and by the concept of fluid loss control. The drilling of formations that contained salt and anhydrite led to the development of starch, and later CMC, as fluid loss additives and to the development of lime-based muds. The late 1950s led to the development of new thinners, such as ferrochrome lignosulphonate, and extended the clay based systems’ tolerance to calcium and temperature. The most recent developments have been concerned with the development of low-solids fluids with improved rates of penetration and water-based fluids that provide levels of shale inhibition close to that of oil-based fluids. These developments have given rise to a wide variety of mud systems, some of which are specialised for one particular area or problem. These systems can be divided into two categories, which relate to the type of solid-solid interactions and flow properties, namely dispersed and non-dispersed. Each of these categories can be further sub-divided into non-inhibited fresh water systems and inhibited systems, including saline fluids. Table 7-1 sets out the mud systems that will be described under each heading. Table 7-1 Classification of Bentonite Fluid S ystems S olid-solid interactions

Inhibition level

Drilling fluid type

Dispersed

Non-inhibited

1.

Fresh water clay based fluids. Sodium chloride less than 1% calcium ions less than 120 ppm a. Phosphate low pH (pH to 8.5) b. Tannin-high pH (ph 8.5-11+) c. Lignite d. Chrome lignosulphonate(pH 8.5-10)

Dispersed

Inhibited

2.

Saline (sodium chloride) fluids a. Sea-water fluids

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b. Salt fluids c. Saturated salt fluids 3.

Calcium treated fluids a. Lime b. Gypsum

4. Non-dispersed

Low concentration lignosulphonate fluids

Non-inhibited

Fresh water-low solids a. Extended bentonite systems b. Bentonite-polymer systems

Non-dispersed

Inhibited

Salt-polymer fluids

This classification system was chosen to highlight the importance of selection of the drilling fluid to the type of formation being drilled. For example, a hard, water insensitive shale may be drilled with a dispersed, non-inhibited fluid, whereas a soft, swelling, dispersive formation should be drilled with a non-dispersed inhibited fluid. The fluid systems will be discussed under these headings. It will be realised that fluid formulations will only apply to the initial make-up. In engineering any fluid system, the interactions between the mud system and the formation often dictate the additions of material required to maintain the system. 7.2 Deflocculants Used in Dispersed Systems These are systems where the viscosity and fluid loss control properties are essentially those imparted by a dispersed, deflocculated sodium-bentonite system. The important characteristics of these systems are the deflocculants that are used to control the build-up of solid-solid interactions, which can give rise to excessively high viscosities and gels. Deflocculation will also reduce the fluid loss. In these systems, bentonite must be hydrated in water containing less than 1% sodium chloride and less than 120 ppm calcium ion. The particular properties of the type of thinners used, defines the overall system application and its limitations. The main deflocculants in use are described below. 7.2.1 Inorganic Phosphates The two phosphates most generally employed are SAPP (sodium acid pyrophos phate-酸式 焦磷酸钠), with a pH of about 4.0, and STP (sodium tetraphosphate), with a pH of about 7.0. Phosphates are very effective deflocculants and react by neutralisation of positive sites on the clays, particularly those arising from aluminium ions. 3

Very low dosage levels are normally required, in the range of 0.29-1.43 kg/m (0.1-0.5 ppb). The materials are acidic, so the pH is usually below 9.0 and normally kept in the range of 8-9 by use of SAPP and STP, where viscosities are minimal. Overtreatment can lower the pH, which can raise the viscosity through clay flocculation. 119

The efficiency of this class of deflocculants is limited by two factors: A.

Temperature: Molecularly dehydrated phosphates can revert by hydration at temperatures above 65℃ (149℉) to monophosphates.

B.

Calcium: Phosphates form insoluble salts with calcium and are thus ineffective as thinners in the presence of high concentrations of soluble calcium. These two factors limit the use of the phosphates to fluids with temperatures below about 65℃ (149℉), which, with normal temperature gradients is only applicable in holes with a maximum depth of about 2,438 metres (8,000 ft). Phosphates may be added to sequester calcium, if sodium carbonate or sodium bicarbonate is not available, but normally would be used in fluids containing less than 100 ppm calcium.

7.2.2 Tannins(丹宁) Tannins were developed to extend the temperature range above that of phosphates, to around 120℃ (248℉). The tannin acids, mainly quebracho or hemlock, have to be converted to the sodium salt by treatment with caustic soda. Therefore, to treat the mud, the tannin is mixed with caustic soda in the ratio of 1:1 or 4:1, dependent on the pH of the mud system. Concentrations of 3

1.43-8.56kg/m (0.5-3 ppb) are normally required and care should be taken to avoid overtreatment, as this may lead to increased viscosities. Tannins are effective at higher pH ranges, above 9.5, and are most effective in lime muds, where the pH is 11-12. Thus, tannins are effective agents against cement contamination. The higher pH allows a greater tolerance to solids, but these fluids are not usually used above densities of 1.4. This type of system has a low tolerance to salt and should not be used in salinities greater than that of sea-water. A chemically modified tannin, Desco, has been developed that retains the effectiveness at low doses, but has increased tolerance towards calcium, salt and elevated temperatures. 7.2.3 Lignites and Chrome Lignites(褐煤) Lignites provide moderate deflocculation action, but only in fresh water muds. The material has only limited solubility and has to be treated with caustic soda before addition to the system. The limited solubility requires higher additions to be made, normally in the range 11.41-25.68 kg/m3 (4-9 ppb). But, as a consequence of the insoluble nature of the material, a level of fluid loss control is achieved. This latter property has particular application in high temperature fluids, where they have been used at temperatures in excess of 230℃ (446℉). Chromium salts may be used to extend the temperature range. Lignites are available that do not contain chromium. The solubility of the material is decreased in electrolytes, so it does not function effectively in salty water above 2% and in free calcium levels above 200 ppm. The insolubility and aromatic humic acid(腐殖酸) structure gives the molecule surfactant properties and this material can be effective as an emulsification aid in oil emulsion fluids. 7.2.4 Lignosulphonates and Metal Lignosulphonates(木素磺酸盐) This group of materials represents a significant technical advance over the materials 120

previously described due to their effectiveness over a wider range of conditions. These can be listed as follows: A.

can be used in both fresh water and salt water environments

B.

excellent resistance to calcium

C.

effective over a wide range of pH value normally 9.5-12.0

D.

effective at temperatures of around 175℃ (347℉)

E.

no overtreatment effects if used in too high a concentration

F.

effective in higher weight fluids

These advantages have ensured a wide spread application of lignosulphonate derivatives in drilling fluids. The complexes with iron and chromium have had greater application, due to increased temperature stability. 7.2.5 Synthetic Polymers Recent developments in polymer technology have led to the introduction of temperature stable polymers, with excellent resistance to calcium. IDTHI N 500 is most effective in fresh and brackish water. Another product of this nature is IDSPERSE HT, which has particular application in saline fluids up to saturated salt conditions. Both products are effective at low doses 3

of 9.57-5.71 kg/m (0.2-2lbs/bbl), are in liquid form to ensure ease of mixing and have a temperature stability in excess of 230℃(446℉). They are also non-toxic in contrast to the chrome containing products. 7.2.6 Surfactants Surfactants can lower surface tension and increase the wetting of clays. These effects will reduce the viscosity of the muds. The surface active agent may be specific for a particular level of salt. This system may have particular application for drilling sticky shales. The essential features of deflocculants are summarised in Table 7-2. Table 7-2 S ummary of characteristics and limitations of deflocculants in bentonite fluids pH

Stability

range

calcium

7-9

100ppm

Type

1. Phosphate

Temperature S alt

stability ℉

poor

149

Normal dose

Application

℃ 65

0.1-0.5 lb/bbl

Surface holes 3

SAPP

0.29-1.43 kg/m

TSP 2. Tannins

9.5-12

poor

poor

248

120

0.5-3 lb/bbl

Fresh water and lime 3

3. M odified Tannin

8-13

good

good

392

200

muds

0.1-3 lb/bbl

All 3

(Desco) 4. Lignites

1.43-8.56 kg/m

Above

200ppm

9

max.

poor

446

230

dispersed

mud

0.29-8.56 kg/m

systems

4-9 lb/bbl

Fluid loss at high temp

11.41-25.68

in fresh water fluids

121

kg/m3 5. Chrome

Above

lignosulphonates

good

good

347

175

Emulsifier for oil

2-4 lb/bbl

Fresh, salt and calcium 3

9.5

5.71-11.41 kg/m

fluids

0.2-2 lb/bbl

Low dose, temperature

FCL 6. Synthetic Polymers

8-10

IDTHIN 500

excellent

Good

482

250-

3

excellent

excellent

500

260

0.57-5.71kg/m

stable

good

Depends

320

160-

1-2 lb/bbl

Stabilises fluids

IDSPERSE HT 7. Surfactants

8-12

2.85-5.71 kg/m3

on type

7.3 Dispersed Non-Inhibited Systems(分散非抑制体系) Drilling fluid systems typically used to drill the upper hole sections are described as dispersed non-inhibited systems. They would typically be formulated with fresh water and can often derive many of their properties from dispersed drilled solids or bentonite. They would not normally be weighted to above 12 ppg (1.44 S.G.) and the temperature limitation would be in the range of 80-90℃(176-194℉). The flow properties are controlled by a deflocculant, or thinner, and the fluid loss is controlled by the addition of bentonite and low viscosity CMC derivatives. A typical formulation is given in Table 7-3. The details of the system are related to the deflocculant used and would be selected on the grounds of the ability to withstand the expected contaminants and temperature. Table 7-3 Typical formulation of a Dispersed Non-Inhibited Fluid Fresh water

1 bbl

1 m3

Bentonite

15-30 lbs

42.8-85.9 kg

Caustic soda

Dependent on deflocculant

Deflocculant

See Table 2

Low Viscosity CM C

1-2 lbs

Barite

As required

2.85-5.71 kg

Within the limitations of the system, treatments are straightforward and may be summarised as follows: A.

Solids. Excessive concentrations of solids can produce unacceptably high viscosities and gel strengths. This can lead to an excessive consumption of chemicals. The level is controlled by dilution with water to the desirable level.

B.

Viscosity. The plastic viscosity is decreased by water additions and increased by bentonite and solids additions. The yield point and gel strengths are decreased by the addition of thinners and increased by bentonite additions.

C.

Fluid Loss Control. Often proper dispersion of the bentonite alone will give a fluid loss in the region of 5 cc's. if lower levels are required CMC or IDFLO may be added.

The advantages may be listed as follows:

122

A.

These systems make maximum use of drilled solids and thus may potentially reduce overall material consumption.

B.

The systems can be converted to a dispersed inhibitive type fluid when required.

C.

The systems can tolerate fairly high levels of drilled solids at the lower mud weights.

The disadvantages stem from the non-inhibited character of the system, which can lead to a very rapid build up of formation solids. This can lead to the following consequences: A.

Unacceptably high viscosities and gel strengths.

B.

Excessively high dilution volumes that increase consumption of treating chemicals and weighting materials, such as barites. In practice this feature often limits these systems to densities below 1.44 (12 ppg).

C.

Dispersion of the clays can lead to severe hole erosion, which will produce problems in directional drilling and cementation of casing.

D.

The uninhibited nature can promote the hydration, or swelling, of water sensitive shales, which may cause heaving or sloughing conditions, balling of the bit, or the formation of "mud rings".

E.

The uninhibited nature may disperse or mobilise clays in sandstone formations and impair the production of condensate from the pores.

F.

The systems are easily and severely affected by common contaminants of soluble calcium and salt, both of which induce flocculation with consequential deteriorations in flow properties (high viscosities and high gel strengths) and fluid loss control(high levels). Chrome lignosulphonate systems have largely overcome these difficulties.

7.4 Dispersed Inhibited Systems(分散型抑制体系) Dispersed inhibitive fluids attempt to combine the use of dispersed clays and deflocculants to derive the fundamental properties of viscosity and fluid loss with other features that will limit or inhibit the hydration of the formation and cuttings. It will be realised these functions are in opposition, therefore the ability of these systems to provide a high level of shale inhibition is limited. However, they have achieved a high level of success and in many formations represent a significant advance over dispersed non-inhibited types of fluids. Inhibition is sought through three mechanisms: 7.4.1 Addition of Electrolyte or Salt(加入电解质或盐) It was shown in Section 4 that the hydration of bentonite could be decreased by an increase in the salt level. The electrolyte may be present for a number of reasons. In many areas, because of economy, convenience or by intention, the make-up or treating 123

water contains salt. On offshore locations, sea-water is an obvious choice of water. A typical sea-water analysis is given in Table 7-4. Note there are significant concentrations of calcium and magnesium that may aid the inhibition mechanism. Treatment with an alkali, such as caustic soda, will remove magnesium hydroxide above pH 10.5-11. Table 7-4 Typical Seawater Analysis Ion Chloride Sulphate

Formula Cl

19,400 2-

SO 4

2,710

2-

Carbonate

CO 3

Bicarbonate

HCO 3-

Bromide Borate

Concentration (mg/l)

-

Br

145

-

66 3-

BO 3 and HBO 32-

Nitrate Phosphate Fluoride Sodium M agnisium Calcium Potassium Hydrogen

25

-

NO 3

0.7 2-

HPO4 F

0.1

-

1.3 +

Na

10,800

+

Mg

1,290

+

Ca

410

K

+

390

H

+

pH 7.5-8.5

Brackish water or formation water which contains over 1% salt or 6,000 mg/l chloride ion would also have an inhibitive effect. Salt may also be derived from the formation, as it is often encountered as a thin stringer or as a massive salt bed. Salt from the formation can be used to increase the salinity if the sections are not too thick and the washed-out sections do not destabilise the hole. In order to drill extensive salt sections, the aqueous phase has to be saturated by the addition of salt. Bentonite is activated and stabilised for these salty inhibited fluids by prehydration in fresh water and treatment with ferrochrome lignosulphonate(铁铬木素磺酸盐) to limit the collapse of the clay structure. In a salty environment, low viscosity CMC and modified starches, such as IDFLO and IDFLO HTR, may be used to reduce fluid loss. A formulation is given in Table 7-5. Table 7-5 Typical Formulation for Bentonite Seawater Fluid (1) Bentonite premix Fresh water Wyoming bentonite Caustic soda

1 bbl

1 m3

45-55 lbs

128.39-156.92 kg

2 lbs

5.71

124

Ferrochrome lignosulphonate FCL

6lbs

17.12 kg

(2) Add 1 volume premix to 1 volume salt water Bentonite premix

0.5 bbl

0.5 m3

Salt water

0.5 bbl

0.5 m3

IDF FLR

0.5-1 lb

1.43-2.85 kg

3-5 lb

8.56-14.27 kg

IDFLO Caustic soda Barite

pH 10.5-11 to required density

The treatment will be essentially that for a dispersed, system. Good quality fines, from the bentonite, should be carefully maintained by a programme of disposal of whole mud and replacement with prehydrated bentonite. The fluid will have good temperature stability up to about 350℉ (180℃). Lignite at 14.27-28.53 kg/m3 (5-10 lbs/bbl) or HIGH TEMP at a similar dose, will provide fluid loss control at high temperature and pressure. At higher salinity levels than seawater the bentonite becomes less effective. One solution is to use higher bentonite doses, but this can overload the system with fine sized particles and cause instability. A better approach is to rely on salt stable polymers to derive the viscosity and fluid loss control. The polymer IDVIS, used at low concentrations of 1.43-4.28 kg/m3 (0.5-1.5 lbs/bbl) will effectively allow the viscosity to be maintained. In particular, it will provide high yield point characteristics to ensure good hole cleaning. IDFLO will ensure that the desired fluid loss control characteristics are maintained. In saturated salt conditions, the solubility and effectiveness of ferrochrome lignosulphate (FCL) deteriorates and a synthetic polymeric deflocculant such as IDSPERSE HT would be more cost effective, as only low doses of 1.43-5.71 kg/m3 (0.5-2 lbs/bbl) would be required. 7.4.2 Calcium Treated Systems The calcium ion can inhibit hydratable formation clays by exchanging with the sodium ions to produce a hydrated but non-expanding complex with a much reduced volume of entrained water. The calcium ion competes very effectively for sodium, so only has to be present in relatively low concentrations of 500-2000 mg/l calcium ion. The effect of the calcium ion on the bentonite clay system is, of course, going to be the same with the conversion to a calcium montmorillonite 125

system. An advantage of that is the stability to calcium in the form of anhydrite and cement. The calcium is maintained in solution by either adding lime (calcium hydroxide) or gypsum(hydrated calcium sulphate). These salts have only a limited solubility in water, so they may be maintained in excess to replace the calcium ion as it is used up in the exchange process. Calc ium inhibition can be supplemented by salt inhibition, when the fluids are formulated with sea-water. Lime-Treated Fluids The solubility of lime is controlled by the alkalinity, which is adjus ted by caustic soda additions. The chemical equations can be written as:

Ca(OH) 2  Ca 2   2OH _ NaOH  Na   OH _ Calc ium hydroxide is a weak base and is only partially dissociated. Sodium hydroxide fully dissociates into sodium and hydroxyl ions. As more hydroxide ions are added, as sodium hydroxide, the dissociation of lime is decreased and the concentration of calcium ions in solution can be adjusted. Lime will dissolve in water to form a solution containing 900 mg/l, calcium ions. This can be adjusted to the working range of 80-200 mg/l with caustic soda. The level of alkalinity is measured by acid titration(滴定) of the filtrate. Lime muds can be discussed under three headings. A.

Low Lime Muds. These fluids offer the least inhibition, but have the greatest temperature stability. Temperature instability arises through the formation of a calcium aluminosilicate, or cement-type material, with consequential thickening of the fluid. Low lime muds are normally used when the temperatures encountered are near the limits for this type of fluid of 135℃(275℉). The excess of lime is maintained at 2.85-5.71 kg/m3 (1-2 ppb) and filtrate alkalinities are in the range 1-2 mis.

B.

Conventional Lime Muds. These fluids offer good inhibition to shales and are tolerant to salt and anhydrite. They are the most commonly used and typically contain 8.56-17.12 kg/m3 (3-6 lbs/bbl) excess lime and have filtrate alkalinities in the range of 3-6 mis.

C.

High Lime Muds. These are the most inhibitive of this type and are employed when the shales and clays to be encountered are particularly hydratable. The excess of lime is maintained in the range 19.97-42.80 kg/m3 (7-15 lb/bbl) and the filtrate alkalinity is 7-15 ccs.

The formulations, apart from the quantities of lime and caustic, are essentially the same. Often the fluids are formulated by conversion, or break-over, of an existing non-inhibited dispersed mud. 126

This can be done during drilling operations. The lime requirement is the amount of excess lime, plus 20%. Normally caustic soda is added to achieve a filtrate alkalinity numerically equal to the excess lime desired. As a guideline the dose required is given by the equation caustic soda lbs/bbl = 1/2(excess lime lbs/bbl-1) + 1. The low concentrations of calcium in the filtrate allow deflocculants, except phosphates, to be used. However, the best results are achieved with tannin or lignosulphonate types. In saline conditions, lignosulphonate types are preferred. A typical formulation for a conventional lime mud is given in Table 7-6 and mixed in the order given. If the conversion is to take place on an existing fluid, care should be taken to dilute the active clay solids to a level where the initial flocculation effects of the lime will not thicken the fluid to the extent where it cannot be circulated. The suction tank should be well agitated and no backflow should exist between this tank and the rest of the system. Ensure that the existing system is not contaminated by the converted fluid. The caustic soda, deflocculant and lime should be added over one circulation. Adjustment of fluid loss with CMC, and/or IDFLO, and weight material to the final level are the final treatments. Table 7-6 Typical Formulation for a Lime-based Fluid Fresh water

1 bbl

1 m3

Bentonite

15-20 lbs

42.80-57.06kg

Caustic soda

2-3 lbs

5.71+8.56 kg

Ferrochrome lignosulphonate

2-4 lbs

5.71-11.41kg

Lime

4-8lbs

11.41-22.82kg

CM C-LoVis and/or

1-2lbs

2.85-5.71kg

IDFLO

2-4 lbs

5.71-11.41kg

Barite

As required for density

The temperature stability can be increased to 150℃(302℉) when lignite is added. Higher temperatures have been accomplished with lignite, sodium chromate and surfactants. The main advantages are the relatively low cost, ease of maintenance at medium densities and the inhibition level given to the shales by calcium exchange. The limitations are the problems of gellation and the limitations of an inhibitive system that maintains high pH values and contains a dispersant or deflocculant. If the formations are too reactive to respond to the inhibition the generation of fine drilled solids can be a problem and may require excessive dilution. Gypsum Treated Fluids 127

Gypsum based fluids were introduced to overcome the gellation problems of lime muds. Here, gypsum or calcium sulphate is added in excess to create a calcium concentration of 600-1200 mg/I in the filtrate. The pH is maintained in the range 9.5-10.5 with caustic soda or lime. Due to the higher calcium levels, ferrochrome lignosulphonate is the deflocculant of choice. A typical formulation is given in Table 7-7. An existing system can also be broken over, but the dilution required must be carefully checked. Table 7-7

Typical Formulation of a Gypsum-Bentonite Fluid

Fresh water

1 bbl

1 m3

Bentonite

15-20 lbs

42.80-57.06 kg

Caustic soda

1.5 lbs

4.28 kg

Ferrochrome lignosulphonate

2-4 lbs

5.71-11.41 kg

Lime

4-6lbs

11.41-17.12 kg

CM C-LoVis and/or

1-2lbs

2.85-5.71 kg

IDFLO 2-4 lbs

5.71-11.41 kg

Barite As required for density

The primary control of the system is to ensure the calcium in the filtrate is maintained in the range 600-1200 mg/l. This system exhibits excellent stability to anhydrite and has a moderate tolerance for salt. The fluid is easy to maintain and has a greater resistance to high temperature gellation, because of the lower pH, and is stable to 165℃ (329℉). Lignite, at 14.27-28.53 3

kg/m (5-10 lbs/bbl), is again used to control fluid loss as the temperature is increased. This system, possibly combined with sea-water salt inhibition, represents the most economical fluid system offering a level of inhibition for shales. 7.4.3 Polymer Treated Systems A third inhibitive mechanism has been invoked for a class of dispersed-inhibitive muds whereby a polymer is added at sufficient concentration to envelop the cuttings and form a viscous layer which will reduce the rate of migration of water attempting to hydrate the clays. The system will be programmed in the same manner as a dispersed system. It may have other inhibiting features, such as gypsum or lime, and may contain some salt. Where the formations show a well developed sensitivity to dispersive action, the system may not be so effective and a non-dispersed inhibitive system should be used. 128

7.5 Non-Dispersed Non-inhibited Systems(不分散非抑制性体系) In non-dispersed systems, no reagents are added to specifically deflocculate the solids in the fluid, whether they are formation clays or purposely added bentonite. The absence of thinners, and a chemically dispersive environment, will provide a level of inhibition. However, this advantage is essentially lost because they are formulated in fresh water. The main feature of these systems is to exploit the higher viscosities and, particularly, the higher yield point to plastic viscosity ratio that are characteristics of a flocculated system. The advantages can be summarised as follows: A.

The lower solids requirement permits lower densities to be used. This reduces chances of loss of circulation and increases penetration rates in low pressured formations.

B.

The altered flow properties provide better hole cleaning. This permits lower annular circulating rates and helps prevent borehole washouts.

C.

The higher degree of shear thinning provides for lower bit viscosities. This permits more effective use of hydraulic horsepower and faster penetration rates. In addition, shear thinning promotes more efficient operation of the solids removal equipment such as hydrocyclones.

Polymers are very effectively used in conjunction with clays to develop the required properties with low, cost-effective doses of both clay and polymer. High molecular weight polymers such as IDVIS, IDF FLR and IDFEXTEND are used to form bridges between clay particles and so develop the highly shear sensitive viscosities required. The fluid loss control function of bentonite is less effective in a flocculated low-solids environment, but can be easily regained by the use of modified starch base product such as IDFLO, which is non-dispersive and therefore preferable to CMC LO-Vis, which has a deflocculating effect. This type of fluid is commonly employed in large diameter top hole sections, such as when spudding. Large dilution rates ensure the solids are at a low level. The high cleaning capacity and low solids--low density characteristics are best exploited in this situation when large holes are drilled in upper low pressure formations. An example of these systems is the extended bentonite system and IDYlS/bentonite system. 7.5.1 Extended Bentonite System In this system, the flow properties of the bentonite are supplemented by a high molecular weight synthetic polymer, IDF EXTEND. A second function of the extender is to flocculate formation solids. A typical formulation is given in Table 7-8. Table7-8 Typical formulation for an Extended Bentonite S ystem

129

Fresh water

1 barrel

1 m3

IDF EXTEND

0.05 lb

0.14 kg

Bentonite

11 lbs

31.38 kg

Soda ash

0.25-0.5 lbs

0.71-1.43

Caustic soda

pH 8.5-9.0

The bentonite should be specially selected for this type of system as being an untreated high yield Wyoming bentonite. The fluid has poor tolerance to calcium and salt, so the make-up water should be of good quality and pretreated with sodium carbonate, if any hardness exists. To increase viscosity IDF EXTEND is added through the hopper at the rate of one pound (0. 5 kg) for every five sacks of bentonite. The extender is dissolved in water in the chemical barrel and added at 1.36-5.44 kg (3-12 lbs) per day, at a rate dependent on the drilling rate. Excessively high viscosities and gel strengths are normally the result of too high a solids content, which should be kept in the range 2-5% by dilution. Dispersants should not be added as they compete too effectively with the extender for the adsorption sites on the clay. A small excess of soda ash, of 0.57 kg/m 3 (0.2 lb/bbl), should be maintained to ensure the calcium level remains below 80 mg/I and to improve the efficiency of the extender. This level of soda ash will produce the required pH in most cases. The API fluid loss will be in the range of 15-30 mls. Further control can be made by the addition of polyacrylate polymer AP-21 or IDFLO. Diesel oil may be included at 5-6% to give improved filtration control as well as lower fluid densities. The system can be weighted to a maximum density of 1.32 (11 ppg) provided the ratio of drill solids to clay solids is maintained at less than 2:1, by correct use of the solids removal equipment and careful dilution and make-up with bentonite from a premix tank. The advantages of the system can be summarised as follows: A.

Very low weight muds can be maintained and the chances of loss of circulation are reduced. Also hydrostatic and formation pressures can be more closely balanced and higher penetration rates achieved.

B.

These systems have good shear thinning characteristics and moderate to high yield point/plastic viscosity ratios. This provides for good hole cleaning at lower annular velocities and more effective use of available hydraulic horsepower. The ECD is also lower and this will reduce the chances of loss of circulation even further.

C.

These systems are economical, as the major constituent is bentonite and the requirement for all components is low.

D.

Oil can be incorporated into the system without special emuls ifiers.

E.

The system is easily converted to all types of dispersed and non-dispersed systems.

130

F.

Flocculation of drilled solids by the extender aids in solids removal. The disadvantages may be summarised as follows:--

A.

Lack of inhibition and the low solids tolerance of the system can give rise to excessive dilution rates in dispersable clays and shales.

B.

The system has a low tolerance for calcium and salt. Encountering cement, anhydrite or salt concentrations will result in having to convert the system if they cannot be diluted or treated out.

C.

Low tolerance for all types of solids and thus can only be weighted to low levels  1.32 S.G. (11 ppg).

7.5.2 IDVlS/Bentonite System In this system, the high molecular weight polysaccharide polymer. IDVIS, is used to extend the rheological properties of bentonite. This system has more stable properties than the Extended Bentonite System, because IDVIS exhibits good rheological properties in its own right, and has a better tolerance to salt and calcium. The system can be formulated to include salt, such as potassium chloride. Such a system, offering a higher level of inhibition, would then be classed as a non- dispersed inhibitive fluid. A typical formulation is given in Table7- 9. Table 7-9 Typical formulation for IDYlS /Bentonite S ystem 1 bbl

1 m3

(prehydrated if salts present)

10 lb

28.53 kg

IDVIS

0.5-1.5 lb

1.43-4.28 kg

2-4lb

5.71-11.41 kg

Water (any type) Bentonite

Caustic soda to pH 8.5-9'5 IDFLO as required

IDClDE L

The system is easily maintained with bentonite and IDVIS added as required. Generally the system would be considered a low density fluid, although densities up to 1.44 S.G.(12 ppg) could be prepared. Care should be taken to limit the build-up of drilled solids so that the viscosity does not become too high. The fluid loss can be controlled by a non-dispersing product such as IDFLO, although CMC-LoVis may have some advantage at higher solids, due to its dispersing action. A bacteriocide, IDCIDE L, should be used in low salinity fluids at one 251.pail/ 31.80m 3 (200 bbl). 131

The system is flexible and could be converted to other systems. The sensitivity of bentonite fluids to calcium and salt is not as pronounced in this system because of the relatively low levels of bentonite and because IDVIS is not affected by these contaminants. 7.6 Non-Dispersed Inhibited Systems(不分散抑制体系) In these systems, the non-dispersed character of the fluids is reinforced by some inhibition system, or combination of systems, such as: A.

calcium ions, lime or gypsum

B.

salt-sodium chloride or potassium chloride

C.

Polymers such as Polysaecharides IDVIS Polyanionic cellulose IDF FLR Hydrolysed polyacrylamide IDBOND

In the presence of these very effective inhibition systems, particularly systems such as potassium chloride - IDBOND Polymer, the role of bentonite is diminished because the chemical environment is designed to collapse and encapsulate the clays since this reaction is required to stabilise water sensitive formations. The clay may have a role in the initial formulation of an inhibited fluid to provide the solids to create a filter cake. Canadian IDBOND Polymer-Potassium Chloride System Bentonite is formulated in the IDBOND Polymer-Potassium chloride system used to drill older formations in the Rocky Mountains that are made up with fresh water. A typical formulation is given in Table 7-10. Table 7-10 Typical formulation of the Canadian IDBOND Polymer-Potassium Chloride S ystem. 1m3

Fresh water

1 bbl

Potassium chloride

10-15 lb

Prehydrated bentonite

6-10 lb

17.12-28.53 kg

IDVIS

0-5-1.5 lb

1.43-4.28 kg

IDBOND

0.5-1 lb

IDFFLR IDFLO to adjust fluid loss

28.53-42.80 kg

1.43-2.85 kg

0.5-1-5 lb

1.43-4.28 kg

2-4 lb

5.71-11.41 kg

Caustic soda to pH 9.5-10. 132

Barite to desired density

Often, the mineralogy of the clays in shales is very complex and mixed layers of minerals are formed with perhaps a limited degree of expans ion. There will also be a quantity of amorphous or non-crystalline material consisting of aluminium hydroxides or silica. This material has an important role to play as the cement material between grains. Shales are mainly compacted sediments containing significant concentrations of clay minerals, with associated minerals such as sand grains, feldspars and carbonates. The rocks have a fairly high level of porosity, but the pore space does not have the channel-like character one associates with sandstone rocks. Rather, the grain to grain contact is born by the associated minerals and the interstitial space is occupied by hydrated packets of clay minerals orientated with the basal plane parallel to the sedimentary plane. This is shown diagrammatically in Figure 3.

Fig.7-1 Diagram to illustrate the structure of shale. Water associated with the clay particles

To minimise the effects of water on a shale, two aspects of the hydration can be modified. One is to replace sodium and calcium ions in the exchange sites of the swelling clay, montmorillonite, with the dehydrated potassium ion to form the least expanded complex. Mica and Chlorite may also accept potassium to reduce swelling, if there was a deficiency of this ion. The second approach is to slow down the rate at which water migrates into the shale by forming a viscous jelly-like coating on the shale surface. Shale inhibition is most effective when both mechanisms are brought into action. The relative levels required for economical inhibition may vary, depending on the nature of the shale and the drilling conditions. 7.6.1 Potassium Ion Inhibition Potassium Chloride is added to provide an excess of potassium ions to compete with the exchangeable ions present in the shales. A higher level of Potassium Chloride is required when sea-water is used to formulate the fluid, in order to overcome the competitive effect of the additional sodium ion. The level of potassium required is also dependent on the level of exchangeable ions in the formation. Since Montmorillonite has an exchange capacity in the order of ten times that of the other clay minerals the concentration of this mineral in the formation is the major consideration. The cation exchange capacity of the shale can be readily measured from methylene blue adsorption analys is and is a reliable guide to the level of potassium ion required. In a fresh water based system drilling an old sediment, such as hard shales, a level of about 3% Potassium Chloride will be sufficient. 133

In drilling a Tertiary sediment with levels of Montmorillonite approaching 25-40% with a sea-water system, the concentration of Potassium Chloride may have to be in the 10-15% range. In the situation where a reactive formation overlies a less reactive formation, experience has shown that the initial high level can be reduced at the bottom of the section without destabilising the upper hole. It will be realised that it is the concentration of potassium ion that is important and control of the inhibitive properties requires a specific measure of that ion. A measure of the chloride ion is only a relevant measure of the potassium concentration in the initial make up. Another feature of this fluid is that the borehole and the cuttings are reacting specifically with the potassium ion which is then removed from the fluid system when the cuttings are separated from the circulating fluid at the surface. As a consequence the Potassium Chloride has to be added continually and at a rate that is proportional to the penetration rate. 7.6.2 IDBOND Polymer Inhibition The polymer IDBOND concentrates at the shale surface to form a viscous jelly-like coating that will plug and seal pores and fissures and so slow down the movement of water into the shale. The polymer also plays a significant role in strengthening the surface material so that it withstands mechanical abrasion. The polymer is a polyacrylamide-acrylate co-polymer with a molecular weight in the region of 10 million. IDBOND owes its unique properties to: A. B. C.

Its strong adsorption onto clay materials, Its very high molecular weight. Its low viscosity at working concentrations.

D. Its steep viscosity versus concentration curve. These characteristics enable it to function as an encapsulating molecule for the shales with only minimal effects on the drilling fluid properties. Its strong adsorption and high viscosity in the adsorbed layer means that it is economical in use. It has also been specially formulated so that it can be easily added to the system. Just as for Potassium Chloride, IDBOND polymer treatment is continuous and is related to the concentration of cuttings entering the drilling fluid, proportional to the penetration rate. A range of drilling fluids have been developed that exhibit, to different degrees, a stabitising effect on water-sensitive formations. The inhibition mechanisms can be described in terms of an exchangeable ion and polymer and can be compared to the IDBOND polymer Potassium Chloride system. The most common inhibitive systems are based on calcium ion exchange, to convert swelling sodium clay systems to the non-swelling, but hydrated calcium form. Figure 2 shows that in this aspect potassium is a more effective ion than calcium. The calcium ion concentration is commonly achieved by the addition of lime(calcium hydroxide) or gypsum (hydrated calcium sulphate). The divalent ion has a strong flocculating effect and thus has a significant effect on the drilling fluid properties. Poly-anionic polymers may be unstable in this environment and clay-based systems will require deflocculating agents or dispersants, such as tannates or ferrochrome lignosulphonates.

134

Also high pH conditions will be created, to control the calcium ion level and to solubilise the dispersants. The high hydroxyl ion content and the use of dispersants tend to offset the inhibiting effect of the calcium ion. Potassium can be used at high levels so that the exchange can take place to an effective level. The monovalent ion will not react with anionic polymers, nor will it exhibit the same flocculating effect on clay solids, as does calcium. Therefore, the system is stable. The effect of Potassium Chloride on the mud system will be the same as that of salt. The use of Potassium salts avoids the problem of high temperature gellation encountered in calcium systems, particularly lime-based ones. The polymer encapsulation mechanism of shale inhibition is evoked for a wide range of systems, some using calcium or potassium as the exchangeable ion. High levels of lignosulphonate are claimed to have an inhibition effect, but the viscosity effect is minimal and the dispersing effect will be the overriding result. High viscosity cellulose derivatives, starch derivatives and polysaccharides, such as Xantham gums, are claimed to have an encapsulating effect. Certainly there are some aspects of the structure of these polymers that contribute towards an inhibition effect. However, the two essential features of IDBOND are missing from these polymers, namely the strong affinity for the clay surface and the very high molecular weight, which results in a high viscosity at low concentrations. 7.6.3 Formulation and Initial Preparation The IDBOND polymer Potassium Chloride drilling fluid system has introduced new concepts of drilling fluid design. The protection of water sensitive shales from hydration and dispersion effects is achieved by the polymer and the potassium ion. The required level of inhibition can be tailored to meet the particular demands of the formation being drilled. The practical drilling fluid system must also possess defined rheological properties and a means of controlling the fluid loss. In addition, the system should be weighted to the required density and be stable to the typical contaminants encountered such as drilled solids, cement and microbial growth. Rheological Properties. Bentonite cannot be used to derive viscosity in this system because the shale inhibition mechanism causes a collapse of the hydrated bentonite, with a consequential loss in viscosity. Rheological properties are controlled by the use of the high molecular weight polymeric viscosifier, IDVIS, which is effective over a wide range of pH and salt concentrations and is stable to 240℃(400℉). The polymeric fluid has unique viscosity characteristics due to well-developed pseudoplastic properties (high viscosity at low shear rates and low viscosity at high shear rates). These fluid properties give very efficient solids carrying capacities. This is important, particularly when large diameter holes are being drilled. It is important to remove the cuttings as quickly as possible so that hydration and mechanical degradation can be limited. The use of water-soluble polymers to derive viscosity allows the formulation of a low solids fluid at low densities, with the advantage of increased penetration rates. Viscosity control is as effective at higher densities, but obviously the advantages of higher penetration rates are lost. The gellation properties of the polymer system give excellent suspension properties

135

without excessive gellation. The fluid generally maintains these characteristics even with a high solids loading, due to the inhibitive non-dispersive nature of the system. When solids removal is carried out efficiently, dispersants or thinners are not normally used. In higher temperature conditions and high weights a polymeric deflocculant, such as IDSPERSE HT would be used. Fluid Loss Control. Fluid loss control in a non-dispersed fluid is achieved through the addition of colloidal

sized articles and through an increase in the viscosity of the migrating

liquid phase. A modified starch based product, IDFLO, provides micron-sized, water dispersible articles to effectively seal the micro-pores in the filter cake. Extensive chemical modification has ensured that the product is stable to shear and temperatures in the order of 132-149℃ (270-300℉) and that viscosity effects are minimal. A variation of the product, with greater temperature stability, is also available under the name IDFLO HTR. DF FLR, a high molecular weight modified carboxymethyl cellulose, gives effective fluid loss control particularly when used in conjunction with IDFLO. The product also provides a secondary function as a viscosifier. The viscosity derived from IDF FLR and IDBOND is lower in a brine than in fresh water. Therefore, it is easier to add the polymers to a Potassium Chloride brine. The tanks are dumped, cleaned and filled with drill water. In offshore locations this is often sea-water. Potassium chloride is then added to obtain the desired concentraon. Several techniques are available to ensure that the salt is handled efficiently. One is the development of "Big Bags", of up to one tonne capacity, with a single valve opening at the bottom of the bag. Straps on the bag enable it to be manoeuvred easily by fork-lift truck, or crane. In certain locations, a saturated brine can be prepared which contains 25% Potassium Chloride. Another technique, that has been patented, is to prepare a high density brine that is stabilised with IDVIS. This enables concentrations of 85% to be achieved in a pumpable form. The pH of the brine is adjusted to 9-10 with Caustic Soda. Sodium Carbonate may be added to treat out magnesium and calcium in sea-water. The polymers IDVIS and IDFLO are then added. IDF FLR is best added to condition a circulating fluid with moderate levels of drilled solids. The addition of IDBOND is best made when circulating and drilling. If the full concentration is added initially, the viscosity will be too high without shear degradation or solids contamination and fluid will be lost over the shaker screens. A typical formulation and expected properties of a freshly prepared unweighted fluid are given in Table 7-11. A small concentration of inert drilled solids is included to provide a filter cake. Table 7-11 Typical formation and expected properties of an unweighted IDBOND Polymer Potassium Chloride fluid Formulation 1 m3

Sea-water

1 bbl.

KCl

25 lb.

73 kg

Caustic Soda

1 lb,

4.3 kg

IDVlS

1 lb.

2.9 kg

IDFLO

4 lb.

11.6 kg

136

IDBOND

1 lb.

2.9 kg

Drilled Solids

10 lb.

29 kg

Properties Density

1.09

Apparent Viscosity (cps.)

15-20

Plastic Viscosity (cps.)

10-15

Yield Point (lb./l00 sq. ft.)

15-21

Gels (lb./100 sq. ft.) 10 sec/10 min

3-5/5-7

Fluid Loss API (100 psi)

5-10 ml

pH

9.5-10

Exercise

137

CHAPTER 8 PROBLEMS RELATED TO DRILLING FLUIDS 8.1 Borehole stability(井壁稳定) 8.1.1 Cause of Borehole Instability (井壁失稳的原因) Presence of mechanically instable formations and water sensitive chemical-physical instable formations are the intrinsic（固有的）factors of borehole instability. Improper technical and engineering measures and excessive hydration and dispersion properties of the drilling fluids applied are the inducing factors of borehole instability. Borehole instability is a result of complexity of actions of varied factors. Unstable formations are predominately shale formations therefore the problem of borehole instability is essentially the problem of shale. 8.1.1.1 Inherent Mechanical Instable Formations( 力学不稳定地层) Some formations themselves are mechanically instable formations because the characteristics of diagenesis(成岩作用 ) and geological-structural movements in their sedimentation process manifest as sloughing, falling, collapsing and creeping when they are exposed in drilling process. These formations include: A. B.

Loose sands, unconsolidated and poor consolidated sand-stones, shale and gravel formations--dispersion, disintegration and intrusion. Shale formations with developed stratification and weak joints--sloughing and collapse.

C. D.

Shatter belts, faulted zones, discordant formation faces--disintegration, falling and collapse. Stressed (compressed, bended and the like) formations generated in process of sedimentation

E.

or by tectonic movements--disintegration, breaking down and falling caused by stress release after exposition. Rock salt, salt domes（岩丘）and Gumble shale---creeping after exposition under overburden load.

8.1.1.2 Water Sensitive Chemical-Physical Instable Formations(理化敏感地层) Water sensitive chemical-physical instable formations are basically shale formations. The instability of these formations derives from hydration and followed swelling, dispersion and disintegration of shale when it is in contact with water. The fundamental components of shale are predominately clays--water containing aluminum silicates such as smectite（蒙脱石） , illite, kaolinite, chlorite etc. Smectite possesses strong cation exchange capacity, high water intake and weak inter-layer linking potential, and is characterized by its upgraded swelling and dispersion nature when it falls in contact with water. However illite, kaolinite and chlorite have relatively lower cation exchange capacity, lower water intake and higher inter-layer linking potential and these clay minerals are characterized by disintegration, and sloughing when they are in contact with water. According to clay mineral content, mineral type, water content, mechanical strength and hydration character of shale, five categories of shale are classified as shown in the following Table (Table 8-1). Table 8-1 Classification of Shale Type

Hard-

MBT

ness

Meq/

Water Type

100g 1

S

20-40

F&B

Clay content, % %

%

ρ

Clay type

(w)

(w)

S

I

25-70

20-30

40.4

5.5

S -I

C

g/cm

Character 3

1.2-1.5

H.D 138

2

H

10-20

B

15-25

20-30

3

VH

3-10

B

5-15

20-30

4

EH

10-20

B

2-10

20-30

5

B*

0-3

B

2-5

5-30

25.4

42.0

0.7

1.5-2.2

L.H.D

38.3

13.0

2.2-2.5

M .D,T.O.S

18.1

8.3

2.3-2.7

E.H.&B,T.O.D&C

15.0

15.0

2.5-2.7

H,L.D,T.O.S

35.0

a)

Clay type：S- Smectite, I-Illite, S-I- Smectite, I-Illite, C-Clorite

b)

Hardness: S-Soft, H-Hard, VH-very hard, EX-Extreme hard, B*-Brittle

c)

Water type: F&B-Free & Bounded, B-Bounded

d)

Character: H.D.-High dispersable, L.H.D-Less high dispersable, M .D-M edium disperable, T.O.S-Tendency of sloughing, E.H.B-Extreme hard & brittle, T.O.D&C-Tendency of dispersion &collapse, L.D-Less disperable

8.1.1.3 Mechanically Induced Borehole Instability(力学原因诱发的井壁不稳定) Improper drilling technical-engineering measures very often provoke borehole instability such as: A. Lower than required mud density can not create an adequate hydrostatic pressure to hold varied down-hole pressures in balance as before the formations are not drilled out. A great number of examples have proved that inherent mechanical instable formations (in particular stressed and structural broken formations) can not be maintained stable by changing their surrounding chemical environment. However, a relatively raised mud density can evidently improve the situation, which was proved by experiments. B.

Reduction of mud column height by pipe pulling out and delayed mud injection may cause formations break down and collapse in particular in adjacent area of surface or intermediate casing shoe.

C.

Surge or swab resulted from excessively fast pulling or lowering of drill string may fracture or break down formations and result in loss of circulation and collapse.

D.

Rude pump starting gives birth to a large pressure surge and cause weak formations to be fractured and collapse.

E. F.

Collapse as consequences of uncontrolled loss of circulation, kicks or blowout. Collapse or fall down of formations irritated by collision derived from excessive pipe RPM and dissembling drill pipe stands by rotary table reversion.

G.

Washout and erosion of borehole wall caused by turbulent flow or long time circulation against an interval of formations.

H.

Collapse caused by collision of drill pipe on "dog leg" or on segments of formations with sudden change of inclination or orientation.

8.1.2 Indications and Judgement of Borehold Instability（井壁不稳定的显示和判断) A. Excessive cuttings on shale shakers and detritus（碎石） of sloughing or caving shale. B.

Borehole packing-off and bottom filled up and abnormal amount of cuttings, pump burst at starting or failure of pump start after a trip in.

C.

Build-up of massive cutting beds manifested by trip lags in defined intervals, difficulty,

D. E.

abnormal pressure or pump burst at pump starting or sudden drill pipe reversion in drill pipe running or reaming operations. Stuffed lower portion of dill collars and bit nuzzles by cuttings. Excessively enlarged hole determined by caliper log.

8.1.3 Obtaining stabilized Borehole and Prevention of Instability (保持井壁稳定,防止坍塌) 8.1.3.1 Get Knowledge on Instable Formations(认识不稳定地层) 139

A.

Collect shale samples of varied intervals and conduct the following tests: X-ray diffraction for petrographical(岩石) and mineralogical analys is.

B. C. D.

Cation Exchange Capacity test. Water content. Expansion test.

E. F.

Dispersion and recovery test. 3-dimentional stress test(三轴应力测试 ).

G.

Capillary Suction Time (CST) test（毛细管吸入时间测试） .

H.

Shale Stability Index or SSI test. According to analysis of the data obtained from above tests, determine the nature

(mechanically instable or hydration sensitive) of the shale and provide reference information for design of casing program, mud system, mud density and other properties, drilling engineering parameters and annular hydraulics program. 8.1.3.2 Properly Determine and Adjust Mud Density(确定和调整钻井液密度) According to a field statistics, 80-90% of cases of borehole instability were provoked directly by loss of mechanical balance of borehole pressures. A great number of field practices show even though strong inhibitive mud systems were used initially or converted from a routine mud system before entry in the instable formations, the borehole instability manifested as sloughing, falling, collapse, trip lags and bottom fill up still occurred frequently. When a water base mud is used, the application of all kinds of available chemical measures for enhancing the inhibitive character of the mud, for example a saturated salt water mud , can not suppress fundamentally the shale hydration and swelling problem, even a W/O invert emulsion or whole oil base drilling fluid is used. The troubles of shale sloughing and collapse of some inherent mechanically-instable formations were still frequently and inevitably encountered. Therefore the nature of borehole instability essentially is a problem caused by mechanically unbalanced borehole pressures, not a chemistry nature problem. Finally an adequate mud density and a necessary borehole hydrostatic pressure are the necessity and the primary guarantee for obtaining a stable borehole. In design of mud density, the consideration must be taken not only on balance of borehole pressure and fracture pressure of the formations but also on maintaining borehole stability of varied formations. When some indications of borehole instability show up, a comprehensive thinking on raising mud density and strengthening chemical inhibitive environment, with the priority on the first one, will give a positive and successful result. However, do not raise mud density too fast and over the formation fracturing limit in order to avoid irritation of loss of circulation and formation break down. 8.1.3.3 Selection of Inhibitive Mud System and Addition of Shale Inhibitive Agents（选择抑制 性钻井液和使用页岩稳定剂） 8.1.3.3.1 Shale inhibitive agents(页岩稳定剂) A. Polymer encapsulator(包被剂): provide borehole stability by encapsulation and enveloping of shale. The products can be selected as KPAM, PHPA, PAC-141, FA-367 etc. B. Inorganic（ 无机盐） inhibitors or electrolytes: Reduce or mitigate (减轻)shale hydration and C.

swelling. These products are KC1, CaO, NaC1, CaSO 4 , CaCl2 and Na2 SiO3 etc. Asphaltic products: Plug and seal shale micro fissures. This kind of products includes Asphalt-S（磺化沥青） , Asphalt-O （氧化沥青） etc.

D.

Cationic polymers: provide borehole stability by encapsulation. The products are as Cat-VS.

140

E.

Others: MMH, organosilicon（有机硅） derivatives, polyglycols etc.

8.1.3.3.2 Inhibitive drilling fluid systems(抑制性钻井液体系) A. Calc ium base mud (lime mud, gypsum mud). B. Salt water mud. C. KC1-PHPA mud. D. E.

Silicate mud or organosilicon mud. Glycol-polyglycol mud（聚合醇钻井液） .

F.

Formate（甲酸盐） mud.

G. Oil base mud and W/O invert emulsion drilling fluid. 8.1.3.4 Proper Drilling Engineering Measures（合适的钻井工艺） A.

Control drill pipe pulling and running speed to avoid excessive surge and swab caused by pipe movement.

B.

Apply adequate pump rate and adjust mud rheological properties to ensure laminar or transitional flow pattern（过渡流型） and reduce borehole mechanical erosion.

C.

Maintain a proper gel strength and start pump gently to avoid excessive surge and swab

D.

pressures. Control pipe rotation speed to reduce drill pipe collision onto borehole wall.

E. Keep a full borehole by pumping mud in annulus during drill pipe pulling process. 8.1.4 Borehole Instability Remedial Procedure (井塌事故的处理) 8.1.4.1 Un-aggravated Cases of Borehole Instability（一般井塌） Abnormal amount of sloughing and caving shale on shakers，excessive torque and drag on trips or connections. The following measures can be taken: A. Raise mud density by an adequate value. B. Increase mud viscosity and gel strength and reduce pump output in a manner to maintain C.

D. E. F.

laminar flow in annulus. Control drill string pulling and introducing speed and start pump gently to mitigate surge and swab for avoiding instability aggravation or sudden collapse that may cause pump burst or stuck pipe. Add shale inhibition agents to enhance mud inhibition capacity and plug micro-fissures of shale formations. Set a thick mud pills or pills treated with LCM before pulling to avoid formation of cutting beds and bottom pack-off. Running drill string by several divided intervals, start pump slowly and circulate mud until it returns or for a couple of minutes. When the bit is one or two singles from the bottom in the end of pipe running process, start pump slowly at a reduced rate and ream the hole to bottom. Circulate mud at normal flow rate for 10-15 minutes and begin drilling if the pump pressure is normal.

8.1.4.2 Severe Cases of Borehole Instability（严重井塌） When severe cases of borehole instability occur, the phenomena as aggravated torque and drag or sudden reverse on connections and trips, abnormal difficulty of pump starting or pump burst, no progress of reaming, stuffing of bit nozzles or lower portion of drill collars by cuttings, sudden abnormal pressure build up or sudden stuck drill pipe may be encountered. The following measures can be taken: A. Raise mud viscosity and gel strengths.

141

B.

C.

Replace the bit with one with large nozzles or with coring bit, or milling pipe. Replace the drill collars and pipes with those of larger sizes to form successively stepped annular sections for easy ascending of shale detritus. Start pump and circulate at 5-8 m above the collapsed sections with reduced pump rate (1/2 normal flow rate). Raise pump rate steadily to normal flow rate then begin reaming the hole with intermediate speed. Repeat reaming this interval up and down till no excessive torque and drag is observed. Try to run the drill string to bottom while circulating the mud and adding some borehole stabilizers such as asphalt products. Drill 20-30 m new hole and then circulate for 2- 3 circles at an enhanced pump rate to bring the sloughing and caving shale out of hole.

D.

Ream the hole 2-3 times after every single is drilled out and short trips must be done for very footage of 300-600 ft.

E. F.

Inject a thick pill against the sloughing and collaps ing section and then pull out. Run a caliper logging（测井）. If there is a greatly enlarged hole section, conduct a cement squeezing job to seal the it.

8.2 Loss Circulation（井漏） 8.2.1 Causes and Types of Loss of Circulation(井漏的原因和类型) 8.2.1.1 Seepage Loss（渗透性漏失） A.

Causes: Seepage loss occurs naturally under normal drilling conditions in formations with permeability higher than 14 D such as unconsolidated sands, massive coarse sandstones, gravels or reef deposits（礁石沉积层） .

B.

Indications: Seepage loss appears generally as repeated or successive losses with a relatively low rate in range of tens of barrels per hour and in most cases no evident pump pressure drop shows. Seepage loss is characterized by eventuality of spontaneous cure through plugging effect of cuttings and mud cake building and tightening. Seepage loss may reoccur

successively in the same formations by improper operational manners as surge or swab pressures derived from brute pump starting or excessively fast introduction of drillpipe during drilling process. 8.2.1.2 Natural Fissure（裂缝） and Cavern Loss（空洞性漏失） A. Causes: This kind of loss of circulation occurs in carbonate（石灰岩）, dolomite and chalk （白云岩） formations with fissures and caverns, faulted formations, discordant formation B.

faces, shatter belts, fractured zones and eruptive cavernous and vugular formations. Indications: Sudden and severe loss of circulation without return and loss rate may reach couple to hundreds of barrels per hour very often accompanied by sudden erratic rates of penetration or drilling break. Usually natural fissure and cavern loss is difficult to cure, or even the well has to be abandoned in the end.

8.2.1.3 Induced Fracture Loss A. Causes: This kind of loss of circulation occurs when formations are fractured by improper engineering operations such as overweighted mud introduction, excessively fast lowering of drill string or brute pump starting. The frequency of induced fracture loss is higher at shoe of or several meters below surface or intermediate casing. B.

Indications: Depending on the magnitude of fracture induc tion pressure and strength of 142

formations, the rate of loss is quite different and some time, loss rate can be hundreds of

C.

barrels per hour or even greater. Grave loss of circulation occurs due to some severe fault engineering measures and is very often accompanied by formation collapse, impossible pump starting or pump burst, stuck pipe or blowout. Formation fracture pressure and fracturing test: When pressure in the borehole is raised to a certain value, it may cause the formation to be fractured and begin to absorb a great mass of drilling fluid from well bore. The hydrostatic pressure in borehole of this case is right equal

to the formation fracture pressure. The formation fracture pressure can be obtained from formation fracture test and the procedure is as follows (Fig. 8-1): A.

Drill 10-20 ft from casing shoe and circulate and clean the borehole.

B.

Shut in the annulus and slowly start the pump and inject mud into drillpipe at a low rate (8.5-17gal/min).

C.

Build a table and record the volume injected and the respective

Fig. 8-1 Fracturing test of curve

pump pressure. Draw a line of variation of pressure versus volume. The injection pressure

D.

should be proportional with the injection volume and the line should be an inclined straight line. Stop pumping at point A where the pressure drifts off the line, the mud begins to flow into the formation. Point A is called leak off point and the corresponding pressure PL is called leak off pressure. Routinely the test is over at this point.

E.

If pumping is continued, the injection volume increases rapidly meanwhile the injection pressure rises up slowly. The injection pressure gets its maximum value and begins to decrease at point B. Point B is called the fracture point of the formation and the injection pressure corresponding to this point is called the formation fracture pressure, represented as P fr.

F.

The formation fracture is induced at point A and it begins to absorb fluid from well bore. However if the injection pressure is reduced at this point, the fracture generated may close and the fluid loss may cease correspondingly. If the pressure rises to point B, the formation fracture is generated permanently and it can’t be closed again and a remarkable loss occurs

and continues indifferently if the pressure gets lower or not. From what mentioned above, the drilling fluid density that induces formation fracture and loss Fig. 13．Modes of particle association of clays can be calculated using the equation below:

 fr    L / 0.052  H Where

8-1

 fr --Drilling fluid density that induces formation fracture, lb/gal

 --Drilling fluid density in well bore, lb/gal PL--Formation fracture pressure, psi 143

H -True vertical depth of the formation, ft 8.2.1.4 Hydrostatic Pressure of Drilling Fluid Column The hydrostatic pressure of drilling fluid is the pressure of drilling fluid column in static state exerted on the bottom of the well.

  0.052     Where

8-2

 --Hydrostatic pressure, psi,

 --Drilling fluid density in well bore, lb/gal,  --True vertical depth of the well, ft.

8.2.2 Prevention of Loss of Circulation(井漏的预防) A.

The following measures can be taken for prevention of loss of circulation: Carefully collect and analyze the regional geological information and properly design casing

B.

program and mud density in different intervals of a well. Reduce surge and swab pressures caused by pipe movement and pump starting by maintaining suitable mud rheological properties.

C.

Determine rational pump rate to ensure effective carrying and suspension of cuttings and to avoid excessive circulation pressure and wash out of borehole wall.

D.

Avoid excessive penetration rate in soft formations and run solid control equipment to prevent overloading and accumulation of cuttings in annulus and undesired rising of mud weight.

E.

Lower and pull drill string in a gentle way and take measures to avoid bit balling.

F.

Break down pipe introduction in several steps and circulate mud for a certain minutes in each step. Start pump slowly and raise pump rate steadily to the normal flow rate when the bit is close to bottom.

G.

Weight mud to the required density in several circulating circles and conduct pressure control procedure as required right away when abnormal pressure formations are encountered.

H.

Control adequate mud filtration and avoid thick and loose mud cake. Maintain proper mud rheological properties and adjust mud viscosity steadily in order to avoid induction of excessive surge and swab. Add a certain amount and proper type of LCM according to the formation nature and mud

I.

properties. 8.2.3 Remedial Measures for Loss of Circulation（井漏的处理） 8.2.3.1 Seepage Loss If pump pressure decreases, and reduced flow rate in flow -line and drop of level in mud tanks are observed during drilling process, it means seepage loss of circulation occurs. The following measures must be taken without delay: A. Stop pump for observation: If loss indications are observed, stop pump immediately and pull the drill string up above casing shoe or 100-165 ft above the loss formation. Inject mud into annulus to make well bore full of mud. Stop pump again and wait for 1-2 hours. If the mud level continues to decrease, try to calculate loss rate. If the mud level in borehole remains unchanged, start pump at a reduced rate (1/2 of normal flow rate), lower drill string slowly about ten feet above the loss formation, and circulate for a certain time, then restore drilling B.

operation if possible. Add some viscosifiers such as lime, CMC, PAC, MMH, XC, bentonite or polymers, or a

144

quantity of thick mud. Add some bridging agents or LCM if necessary. C.

If loss indications are no more observed, restore drilling with a reduced pump rate and lowered penetration rate till loss of circulation ceases completely. 8.2.3.2 Partial Loss One of the following measures can be taken based on the specific conditions.

A.

Add some viscosifiers and LCM of different shapes and sizes.

B.

Pump a pill of thick mud mixed with 30-40 lb/bbl LCM of varied shapes and sizes against the

C.

loss interval. Pull up drill string into casing or 65-165 ft above the loss formation and wait for 6- 8 hours. Squeeze a high filtration barite-diatomite slurry into the loss zone at a lowered rate. The formulation of barite-diatomite slurry is shown in the following table (Table 8-2). Table 8-2 Formulation of P reparation of 1 bbl Bentonite-Diatomite Slurry Slurry Density, lb/gal

Water, bbl

Diatomite,

lb

Barite, lb

0 15

9.0

0.87

50

10.0

0.84

50

11.0

0.80

47

12.0

0.77

42

30 45

13.0

0.74

14.0

0.70

15.0

0.67

38 34 32

58 73 88

16.0

0.63

17.0

0.60

28 25

100 115

18.0

0.56

19.0

0.52

22 17

130 145

8.2.3.3 Loss of Circulation without Return A. Squeeze and set cement or soft plug slurries. Extensively used plug slurries are quick setting bentonite-cement, diesel-bentonite, lime-bentonite plug and quick setting cement slurries(纯水泥浆 ). The formulations of these plug slurries are not standardized and usually determined and modified by pilot test according to the practical conditions. However the slurries must possess a certain flowing property, initial setting time and strength after consolidation, and if the loss formation is also a productive one, they must be able to be acidized. a) Type and formulation of plug slurry (for reference) Quick setting bentonite-cement slurry (Table 8-3). Table 8-3 Formulation of Quick Setting Bentonite-Cement Slurry Wat er 3

10.0l b/ gal B ent onit e s lurry 3

1m

0.365 m

1 bbl

0.365 b bl

C em ent

Li m e

NaOH

Na2SiO3

1820 kg

455 kg

9 1k g

270 kg

637 1b

159 1b

32 1b

95 1b

The initial setting time of this kind of slurry is about 35-40 minutes so the squeezing operation can begin only when all preparatory work is surely conducted, and surface equipment and connections should be dissembled and washed out immediately after squeezing is over. ② Bentonite-cement slurry (Table 8-4). Table 8-4 Formulation of Diesel-Bentonite Slurry 145

Slurr y Volu m e

C em ent

B ent onit e

Diesel

1 m3

440 kg

440 kg

0.72 m 3

1 bbl

154 1b

154 1b

0.7 2 b bl

③ Diesel--bentonite slurry (Table 8-5) Table 8-5 Formulation of Diesel-Bentonite Slurry Slurr y Volu m e 3

B ent onit e

Diesel

1m

0.70 m

3

805 kg

1 bbl

0.7 0 b bl

282 1b

④ Lime-bentonite slurry: 11.3- 11.7 lb/gal lime solution: 10.0 - 10.4 lb/gal bentonite s lurry = (1: 1), (1:2) or (2: 1). In the above lime-bentonite slurry prepared, a certain amount of NaOH and Na2 SiO3 and an adequate proportion of LCM of different shapes and sizes can be added and mixed so that the plug slurry after setting will capture an increased strength. b) Slurry squeezing procedure. ① The volume of slurry prepared must be larger than the volume of the borehole column of a hight from 5 -8 m above the loss formation to well bottom. ② Locate the loss zone and lower drill string to the top of the loss zone. ③ Pump each 3 - 6 bbl of diesel oil in front and after the slurry as a spacer fluid. ④ Close annular BOP and pump mud at a rate of 2 - 4 bbl/min from wellhead into annulus while displacing the plug slurry at a rate of 4 - 4.5 bbl/min into drill string then in annulus up. After 50 % of the slurry comes out from bit in annulus, continue mud pumping into the annulus with reduced rate of 1 - 2bbl/min and slurry replacing into drill string with a reduced rate of 2 -2.25 bbl/min. After 3/4 of the slurry is replaced into annulus, try to keep a pressure of 100 -500 psi at standpipe gauge to squeeze the slurry into the loss zone until the moment when about 1 bbl of slurry remains in the drill string. ⑤ Pull drill string up into casing and let the plug slurry to stay for 8 - 10 hours. B. C.

Drill blind without return and attempt to cure the loss by plugging effect of cuttings. Change to drilling with foam, mist or air.

D.

Introduce casing to seal the loss zone, this is the most safe and certain measure.

Nomenclatures: 1)  fr --Drilling fluid density that induces formation fracture, lb/gal. 2)

 --Drilling fluid density in well bore, lb/gal.

3) PL --Formation fracture pressure, psi. 4) H --True vertical depth of the formation, ft. 5)  --Hydrostatic pressure, psi. 8.3 Drilling String Sticking（卡钻） Drill string sticking can be divided into the following types: differential pressure sticking, cutting precipitation sticking, cutting bridge sticking, formation collapse sticking, tight hole sticking, key-seat sticking and falling object sticking. The first five types are directly related to 146

drilling fluid and the differential pressure sticking is the most frequently encountered. Different types of sticking are provoked by different causes, have different indications and must be treated with different measures. 8.3.1 Differential Pressure Sticking 8.3.1.1 Causes and Influencing Factors When a section of drill string stays in contact with borehole wall of a permeable formation for a interval of time, the string may be pressed tightly into the wall and the driving power on the string can not overcome the friction and adhesion of the string on the wall surface and the string can't be moved (pulled up, lowered down or rotated) under the differential pressure between the mud hydrostatic pressure and the formation pressure--a differential pressure sticking occurs. In most cases of differential pressure sticking, even though the drill string can't move however the circulation is undisturbed and pump pressure is almost the same as before sticking. The following equation can presumably describe the frictional force between drill string and borehole wall (Eq. 8-3).

F   A( ph  pP ) Ph

F    A( 0 . 0 52  H Pp

)

8-3

Where, F--Friction or adhesion force between drill string and borehole wall, lb,

 --Friction coefficient between drill string and borehole wall, dimensionless, A--Contact area of drill string on borehole wall, in 2 ,

ph --Mud hydrostatic pressure, psi,

 --Mud density, lb/gal, H--Depth of sticking point, ft,

pP --Formation pore pressure, psi. The factors that influence friction or adhesion force on differential pressure sticking are the following three: A.

The higher the differential pressure (

ph  pP ), the greater the adhesion force F. That means

if the drilling fluid hydrostatic pressure H is larger) and the formation pressure B. C.

ph is higher (or the mud density  is higher and

pP is lower, the adhesion force F is greater.

The greater the contact area A, the greater the adhesion force F.

The greater the friction coefficient  , the greater the adhesion force F. On the other hand, differential pressure sticking is greatly related to time. The time in which

drill string is left unmoved on the borehole wall is longer, then the contact area is larger and the friction coefficient  is higher, finally the adhesion force F is higher. The frequency of differential pressure sticking is much higher in directional and horizontal wells because the drill string above the driving device of the bit is unmoved and lying on the lower wall of the borehole in drilling process. The mechanism of differential pressure sticking is shown in Fig. 8-2.

147

Figure 8-2 Differential pressure sticking mechanism

8.3.1.2 Prevention Measures A.

Apply a reasonably lower mud density.

B.

Select adequate drilling fluid system. Maintain low filtration rate, thin and tough mud cake and low cake friction coefficient. Run solid control equipment properly to maintain reduced total solid and low-gravity harmful solid content and low cutting content in annulus.

C. D. E.

Move drill string accordingly in process of mud circulation and equipment repairs. Add some mud lubricants to improve lubrication character of mud and mud cake.

The lubricity of different lubricants and drilling fluid systems are listed in the following tables (Table 8-6, Table 8-7). Table 8-6

Lubricants None

Comparison of Various Mud Lubricants Concentration

In

In

lb/bbl

Wat er

Mud A

0

0.36

0.44

In a

Mud B

b

0.23 148

Diesel oil

0.1

0.23

0.38

0.23

Asphalt Asphalt and di esel oil

8

8 (As phalt ) 0.1 (Di es el oil)

0.36 0.23

0.38 0.38

0.23 0 .23

8

0.36

0.40

0.23

8 (Graphit e) 0.1 (Dies el oil )

0.23

0.40

0.23

Sulphonat ed fatty acid Fatty acid Long chained alcohol Heavy alkylate Petroleum sulfonate Mud detergent brand X Mud det ergent brand Y

4

4

0.17 0.07 0.16 0.17 0.17 0.11 0.23

0.12 0.14 0.40 0.36 0.32 0.32 0.32

0.17 0.17 0.23 0.23 0.23 0.23 0.23

Mud det ergent brand Z Heavy metal soap

0.15 5.27

0.38 0.28

0.23 0.40

0.23 0.23

Silicate Commercial detergent Chlorinated paraffin

4 4

0.23 0.25 0.16

0.30 0.38 0.40

0.26 0.25 0.25

Blend of modifi ed triglycerides and

4

0.07

0.06

0.17

8

0.25

0.30

0.25

0.07

0.06

0.25

0.36

0.44

0.26

Graphite Graphite and Diesel oil

4 2 4 4 4

4

alcohols Sulfonated asphalt

0.1 （ Diesel oil ） and 8

Sulfonated asphalt and dies el oil

( Sulfonated-asphalt)

Walnut hulls (fine) a M ud A-15 g bentonite in 350 ml water

10

b M ud B-15 g bentonite, 60 g Glen Ross shale, 3 g chrome lignosulfonate, 0.5 g caustic soda in 350 ml water

Table 8-7

Lubrication Coefficient of Different Types of Drilling Fluids

Types of Drilling Fluid

Lubrication Coefficient

Drilling fluid with organic thinner (14.5 lb/gal)

0.28

Drilling fluid with organic thinner (12.0 lb/gal)

0.26

Drilling fluid with organic thinner (10.0 lb/gal)

0.25

Sea water drilling fluid(12.0 lb/gal)

0.23

Saturated salt water drilling fluid

0.27

Saturated salt water drilling fluid with lubricant

0.18

Salt water drilling fluid with lubricant (10.8 lb/gal)

0.17

Oil base drilling fluid

0.13

8.3.1.3 Spotting for Stuck Pipe Release The effective procedure for releasing the stuck pipe is submersing the stuck interval of the drill string by spotting fluid. A. Preparation of spotting fluid. a) b) c)

The density of the spotting fluid prepared must be equal to the mud density applied. According to the requirements of environment protection, an oil base spotting fluid can be prepared with diesel or mineral oil. The spotting fluid prepared must have good rheological properties and higher filtration and the filtrate must have high percolating character.

d)

The volume of the spotting fluid must be able to submerge the whole stuck interval of 149

e)

the drill string with a reasonable surplus, usually 100- 125 bbl. For preparation of oil base spotting fluid, warm up the base oil to 104℉(40℃) then slowly add PipeFree (or Pipelax) into the base oil though mixing hopper. Circulate and blend the solution for 30-40 minutes. An adequate percentage of percolating surfactant may help the stuck drill string be released quickly. Be aw are of that percolating surfactant may damage the mad cake quality of whole borehole interval submerged. Weight the spotting fluid with barite to the designed density.

B.

Spotting procedure. a) Wash pump with diesel for oil base spotting fluid and 20 % concentration NaCl brine for water base spotting fluid before preparation. b)

c)

Inject the spotting fluid into drill pipe then replace it into annulus to submerse the stuck interval in such manner that the volume of the spotting fluid in drillpipe is 12-19 bbl more than in annulus. Slowly move the drill string up and down till the pipe release. Circulate the spotting fluid out of hole after pipe release. Collect and store it in a container for next use. Do not leave the spotting fluid in borehole or mix it with drilling fluid because it contains a percentage of percolating agent that will spoil tightness and texture of the mud cake.

d)

Start pump and circulate borehole mud for a certain time while moving and rotating the pipe, then restore drilling.

Formulation of oil base spotting fluid can be seen in the following table (Table 8-8). Table 8-8 Formulations of Oil Bade S potting Fluids Formulation A

Formulation B

M aterial

Specification

Quantity

M aterial

Specification

Quantity

Diesel

0# or 10#

100 m3

Diesel

0# or 10#

100 m3

Oxidizedas phalt

S.P = 150℃ M esh=80

12 t

Oxidized asphalt

S .P = 150℃ M es h = 80

20 t

Organophilic bentonite

M es h=80-100

1.6 t

Organophilic bentonite

C .C =90%

3t

Oleic acid

A . V= 190-205 I.V= 60- 100

1.8 t

Oleic acid

A. V= 190 -205 I. V= 60 - 10 0

2t

Percolating agent

P.P= 100±5%

1.6 t

Percolating agent

Lime ABS

M esh =120 /

3.0 t /

Lime ABS

SPAN-80 Water

/

/ 5.0m3

SPA N -80 Water

Barite

M esh =200 ≧4.20 g/ cm 3

As req.

Barite

S.P—Softening point, 200 C.C— Colloid content, A.V—Acid value, ,03*4.20

1.6 t M esh= 120

1/50 Na 2Cr2O7 solution M esh=200 ≧4.20 g/ cm 3

40. 0 t 2.0 t 0.5 t 5.0 m3 As req

I.V—Iodine value, P.P—Percolating potential.

g/cm3

8.3.2 Cutting Precipitation Sticking and Cutting Bridge Sticking(沉砂卡钻和砂桥卡钻) 8.3.2.1 Causes and Indications A. Cutting precipitation sticking: Precipitation of abundance of cuttings onto bottom may cause stuck pipe when pump is suddenly stopped since low mud viscosity and gel strength and severe accumulation of cuttings in annulus resulted from excessively high penetration rate 150

and poor mud suspension capacity. On the other hand, the bit may intrude into cuttings B.

precipitated on bottom and stuck pipe may occur at pipe connections. Cutting bridge sticking: Cutting bridge may be built up in borehole steps formed by presence of a series of alternations of soft swelling shale formations overlapped by sloughing shale formations. If pipe lowering is too fast, the bit may intrude into the cutting bridge and it results in cutting bridge sticking. In most cases when cutting precipitation or cutting bridge sticking occurs, the circulation path

is stuffed, start of pump and pipe movement is impossible. However some gentle cases may also be encountered when the circulation path is partially stuffed, circulation can be carried out but with higher pumping pressure and reduced rate, and the drill string can be moved in a longer or shorter limited range. 8.3.2.2 Prevention Measures A.

Maintain good mud rheological properties and its satisfactory currying and suspension capacity.

B.

Control penetration rate in soft formations, circulate mud for a couple of minutes then

C.

conduct connections at every single drilled out. Remove drill cuttings on time and maintain borehole and bottom clean by application of

D.

proper annular hydraulics and running solid control equipment. Gently lower the drill string while vigilantly watch pump pressure gauge and weight indicator.

E.

Avoid long-term circulation with bit unmoved against an interval of hole in order to eliminate

borehole erosion. 8.3.2.3 Remedy When cutting precipitation or cutting bridge sticking occurs, sudden pump starting with high output or rode drill string pulling and pressing must be avoided since these manners will make the case even worse and result in pump burst, irritate formation fracturing and loss of circulation. A.

In case when the circulating path is not stuffed and circulation can be established, start pump slowly with reduced pumping rate and at the same time move the drill string with care in order to loosen and wash out the cuttings precipitated and cutting bridge with steadily increased pump rate and lowered pump pressure. This way may realize the pipe release in the final. Sometimes injecting a spotting fluid may also help to get a positive result.

B.

In case when the circulating path is completely stuffed and circulation can' t be curried on, try to rebuild circulation using a cementing truck and circulate with steadily increased pump rate meanwhile gently move drill string to loosen and wash out the cuttings in order to realize removing the stuck pipe. If it fails, the unique remaining way is to do fishing work.

8.3.3 Formation Collapse Sticking(缩径卡钻) 8.3.3.1 Causes and Indications Formation collapse sticking is caused mainly by sudden formation collapses that result from surge or swab provoked by rude pipe pulling, lowering or collision of drill string on borehole wall or improper starting of pump. Lumps and blocks of formation rocks broken fall down in annulus and make the drill string stuck. Formation collapse sticking is characterized by the suddenness of its occurrence, with less possibility of circulation and with obstruction of drill string movement. 8.3.3.2 Prevention and Remedy The principal manners for prevention of formation collapse sticking are enhancing borehole

151

stability by raising mud inhibition and avoiding surge and swab caused by pump starting and pipe movement. When formation collapse sticking occurs, do not take some rude measures such as enforced pulling or lowering drill string instead of application of some gentle manners. If circulation can be built, start pump and circulate mud with steadily raised mud viscosity and gel strength and carefully adjusted pump output, pull and lower the drill string gently. Introduction a spotting fluid may also be helpful to final release. 8.3.4 Salt Creeping and Tight Hole Sticking（岩盐层塑性蠕动缩径卡钻） 8.3.4.1 Causes and Indications Rock salt at temperature over 212 ℉ (100℃ ) changes into a plastic state. When a rock salt formation is drilled out, it will expand or creep continuously into borehole as a plastic object under the over-burden pressure of the formations above and cause trip difficulty, or even worse, it may result in sticking. Besides rock salt, some strong sticky swelling shale formations can expand uninterruptedly into bore-hole due to its strong hydrating and swelling nature. This kind of shale is widely encountered, for example Gumble shale in North sea and a red soft shale formation in Shengli Oilfield, Shandong Province, China. 8.3.4.2 Prevention and Remedy The creeping of rock salt and the related down hole troubles can be resolved only by raising mud density and borehole hydrostatic pressure to balance the overburden pressure, usually the 3 mud density must reach 2.40 g/cm or more. Such high mud density may bring a series of troubles to down hole safety and mud maintenance, therefore if the presence of rock salt formation is known in advance, sealing it by introduction of casing must be considered. In order to control the strong hydrating and swelling soft and plastic shale formations, a strong inhibitive mud system must be selected for use meanwhile adequate high mud density and proper drilling engineering technology are undoubtedly necessary to be applied. If the troubles can't be effectively solved by using a water base mud, re-placement of the water base mud by a W/O invert emulsion or a whole oil drilling fluid can be considered. 8.3.5 Key Seating Sticking（键槽卡钻） The key seating sticking is originated from inserting of drill string into a key seat in an interval of formation. It is not related to drilling fluid and is characterized by sudden occurrence with normal circulation pressure as before and without an abnormal amount of sloughed or collapsed shale on shakers. This kind of sticking occurs repeatedly at imprudent pulling and lowering of drill string but always in the same depth and may be released very often by certain manipulation of string movement. It is important to identify and differ the key seating sticking from other mud related types of sticking at the first moment when it occurs and not to carry out mud treatments and spotting blindly. 8.3.6 Falling Object Sticking(落物卡钻) Failing object sticking is provoked by falling objects such as bit cones or some pieces of manual tools or other equipment into borehole and it is characterized by no observation of rising of pump pressure and absence of excessive cuttings on shakers. Identify the falling object sticking nature as soon as possible so that the proper remedial measure can be taken. For elimination of the trouble, try to pull the drill string out of hole by back off, cutting or exploding the drill string above the sticking point and eliminate the fish and the objects in the hole by milling. Exercise

152

CHAPTER 9 SOLDI CONTROL 9.1 Solid Contained in Drilling Fluid(钻井液中的固相) Solids contained in drilling fluid inc lude bentonite, weighting materials and drilled solids (drilled cuttings of formation rocks or formation detritus derived from sloughing or collapse). Weighting materials have higher density (usually > 4.0 g/cm3 ) and are called high-dens ity solids, and bentonite and drilled solids have lower density (usually <2.7 g/cm 3 ) and are called low-density solids. Weighting materials and bentonite are useful solids and drilled solids are useless or harmful solids. 9.1.1 Bentonite Bentonite is strongly hydratable and swelling active clays and its chemical composition is water-containing silicates-aluminates that can be dispersed into water as very fine colloidal particles (<2 μm) there-with form a stable colloidal suspension. Particle size distribution of a bentonite in fresh water can be seen in Fig.9-1.

Fig. 9-1 Particle size distribution of a bentonite in fresh water

Bentonite is a useful and important solid component of drilling fluid because it can provide the drilling fluid with the following necessary behaviors: A. B. C.

Rheological properties as PV, YP and gel strengths. Filtration, mud cake building and borehole wall strengthening. Carrying and suspension capacity of drilled cuttings and weighting materials. Cation Exchange Capacity (CEC) is a parameter that represents the activity of the bentonite.

The higher the CEC value is, the greater the bentonite ability to build up viscosity at a given concentration. The CEC values of different clay minerals are listed below in Table 9-1. Table 9-1 CEC of Different Clay Minerals

Clay Mineral

CEC, meq/l00g Dry Clay

M ontmorillonite

70-130

Vermiculite

100-200

Illite

10-40

153

Kaolinite

3-5

Chlorite

10-40

Attapulgite, Sepiolite

10-35

Na-Bentonite (Xiazijie, China)

82.30

Ca-Bentonite (Gaoyang, China)

103.70

Ca-Bentonite (Weifang, China)

74.03

Ca-Bentonite (Quxian, Sichuan, China)

100.00

The bentonite of higher CEC is preferable to be applied because it may provide the drilling fluid with upgraded behaviors and performance at its minimum content. Recommended range of properties and low density solids of weighted water base mud is illustrated in Fig. 9-2 and 9-3.

Fig. 9-2 Plastic viscosity, yield point and M ethylene Blue Test (M BT) range for water-base muds

Fig. 9-3 Solids range for barite weighted water-base muds

Bentonite content of a drilling fluid must be controlled in a desired range for obtaining satisfactory drilling fluid properties. The mud with insufficient bentonite content can't obtain good enough properties but if the mud has excessive bentonite content, it may lose necessary good rheological properties that can cause bit-bailing, heavy loading of drilled solids in mud and difficulty of running of solids control equipment, higher surge and swab pressure, difficulty of pump starting or some down hole accidents such as differential sticking or loss of circulation etc. The yield curve of different clays can be seen in Fig. 9-4.

154

Fig. 9-4 Typical clay yield curve A good salt clay in salt water approximates the bentonite yield curve in fresh water

9.1.2 Weighting Materials A good weighting material should meet the following requirements: A. B. C. D.

Higher density. Chemically inactive or inert. Low hardness and abrasiveness. Safe to labor health.

cm3

Barite (barium sulfate) is the most widely used weighting material as it has a S.G. of 4.20 3

g/cm , totally inactive and inert and of abundant existence. API specifications of barite are shown in Table 9-2 and the routine particle size distribution of barite is shown in Fig.9-5. Besides barite, powders of limestone ( CaCO3 ), hematite (Fe2 O3 ) and ilmenite (FeTiO3 ) can also be used as weighting materials.

155

Fig. 9-5 Particle size distribution of a barite

Table 9-2 API S pecifications of Barite Requirements

Standard 3

Density

4.20 g/cm ,minimum

Water soluble earth metal,as calcium

250 mg/kg, maximum

Residue greater then 75 μm

M aximum mass fraction 3.0%

Particles smaller than 6 μm in equivalent spherical diameter

M aximum mass fraction 30%

9.1.3 Drilled Solids Drilled solids are cuttings of bit broken formation rocks or detritus derived from formation sloughing or collapse and intruded into drilling fluid in drilling process. They are predominantly clays, shale, quarts, feldspar as well as limestone, dolomites etc. The specific gravity of drilled solids is ranging from 2.0 to 3.0 g/cm 3 (routinely taken 2.6g/ cm3 ). The particle size of drilled solids is distributed in a very large range (Fig. 9-6).

Fig. 9-6 Particle size distribution of a shale in a native mud

Because the petrographic and mineral components of varied drilled solids are quite different, they may be active on somewhat degrees or totally inactive and with different size range. The drilled solids may generate significant harmful results in drilling process. In the strict sense, almost all drilled solids are undesirable and harmful, with limited exceptions, and they should be eliminated from drilling fluid. The tolerable content of drilled solids in drilling fluid is less than 6 % (V/V). 156

Harmful effects of drilled solids on drilling fluid: A. B. C.

Uncontrolled increase of viscosity. Poor and thick mud cake and increased friction and abrasiveness of mud and mud cake. Accelerated wear of equipment parts. Enlarged eventuality of differential sticking.

D.

Reduced rate of penetration, bit life and footage.

E.

Increased frequency of bit-bailing, increased surge and swab pressure and eventuality of loss

F. G.

of circulation and borehole wall collapse. Greater consumptions of water and chemical additives for mud maintenance. Lost control on increase of mud density, varied down hole troubles and aggravated formation

H.

damage. Enlarged mud drainage and haul-off.

The physical and chemical characteristics of solids contained in drilling fluid are listed in Table 9-3. Table 9-3 Physical and Chemical Characteristics of S olids Contained in Drilling Fluid No.

Characteristics

Bentonite

Barite

Drilled S olids

1

Usage

Colloidal particles

M ud Weighting

Useless, harmful

Barium Sulfite

Low quality clays, and

(BaSO 4)

other minerals or rocks

Active

Inert

Inert & less active

2.3-2.6

4.20

2.0-3.0

Addition

Broken formation rocks

2

Petrographical

&

Smectite

M ineralogical Components 3

Chemical Activity 3

4

S.G., g/cm

5

Source

6

Particle Size

Addition or formation dispersion <5 (about 90%)

< 74

> 6- 10 usually referring to those>74μm

7

Abrasiveness

No

No

High

8

M ohs Hardness

Low

Low

High

9

Acceptable Content

30-60

As required

Varied in a large range, must be eliminated

9.2 Contents and Purposes of Solid Control(固控的内容和目的) Contents of Solids Control A. B.

Elimination of drilled solids. Elimination of excessive bentonite content and colloid particles.

C. D.

Recovery of barite. Recovery of chemical additives and water.

Purposes and Significance of Solids Control A. Maintain adequate mud rheological and filtration properties. B. C. D.

Improve lubricity and reduce abrasiveness and friction of mud and mud cake. Reduce drilling torque and drag. Reduce frequency of differential sticking and logging troubles.

E.

Reduce surge and swab pressure. 157

F.

Increase penetration rate and prolong bit footage and life.

G. H. I. J.

Reduce water, barite and chemical additives consumption. Smooth casing running and improve cementing quality. Obtain gauge hole and enhance borehole stability. Reduce wear of pump and equipment parts.

K.

Control mud weight and mitigate formation damage.

L.

Reduce mud drainage and haul-off.

9.3 Solid Control Equipment(固控设备) 9.3.1 Shale Shakers(振动筛) A. Capacity and efficiency of shale shaker The volume of fluid processed per unit of time by a shale shaker depends on the following factors: a) Type of screen motion. The type of motion of shaker screen will influence the ultimate position of the vibrating assembly relative to the deck of the shaker and the motion track of cuttings. It can be:circular, circular-elliptical or linear. b) c) d)

Vibrating amplitude of the screen. Vibrating frequency of the screen. G-force: This is the force imparted by the vibrating system of the shaker to the screen surface to vibrate for solids separation. For conventional shakers G-force = 3 and for strong shakers G-force = 4-6.

e) f) g) B.

Mesh and weaving type of screen cloth. Drilling fluid properties such as density, PV, YP and gel strengths. Load of solid on the screen (increases with the increase of pump output and mud solid content).

Screen cloth（筛布）

There are great varieties of screens that are characterized by structure design of the screen, mesh, aperture size and shape, open area, mode of weaving of the cloth. The specifications of common oilfield screens can be seen in Table 9-4 and the equivalent screens used by varied firms are listed in Table 9-5. Table 9-4 API S creen Designation Chart Mesh

Opening

Wire diameter

Open area

API Designation

in

in

μm

%

8x8

0.028

0.097

2464

60.2

8x8 (2464x2464, 60.2)

10  10

0.025

0.075

1905

56.3

10  10 (1905  1905,56.3)

12  12

0.025

0.060

1524

51.8

12  12 (1524  1524,51.8)

14  14

0.020

0.051

1295

51.0

14  14 (1295  1295,51.0)

16  16

0.018

0.0445

1130

50.7

16  16 (l130x 1130,50.7)

18  18

0.018

0.0376

955

45.8

18  18 (955  955,45.8)

20  20

0.017

0.033

838

43.6

20  20 (838  838,43.6)

20  8

0.020/0.032

0.030/0.093

762/2362

45.7

20  8 (762  2362,45.7)

30  30

0.012

0.0213

541

40.8

30  30(541  541,40.8)

30  20

0.015

0.018/0.035

465/889

39.5

30  20 (465  889,39.5) 158

35  12

0.016

0.0126/0.067

320/1700

42.0

35  12 (320  1700,42.0)

40  40

0.010

0.015

381

36.0

40  40(381  381,36.0)

40×36

0.010

0.0178/0.015

452/381

40.5

40×30

0.010

0.015/0.0233

381/592

42.5

40×20

0.014

0.012/0.036

310/910

36.8

40×36 (452×381,40.5) 40×30 (381×592,42.5) 40×20 (310×910,36.8) 50×50 (279×279,

50×50

0.009

0.011

279

30.3

50×40

0.0085

0.0115/0.0165

292/419

38.3

30.3) 50×40 (292×419,38.3)

60×60

0.0075

0.0092

234

30.5

60×40

0.009

0.0077/0.016

200/406

31.1

60×24

0.009

0.007/0.033

200/830

41.5

60×60 (234×23 ,30.5) 60×40 (200×406,31.1) 60×24 (200×830,41.5) 70×30

70×30

0.0075

0.007/0.026

178/660

40.3

80×40

0.007

0.0055/0.018

140/460

35.6

(178×660,40.3) 80×40 (140×460,35.6)

100×100

0.0045

0.0055

140

30.3

120×120

0.0037

0.0046

117

30.9

150×150

0.0026

0.0041

105

37.4

100×l00 (140×140,30.3) 20×120 (117×117,30.9) 50×150 (105×105,37.4) 200×200

200×200

0.0021

0.0029

74

33.6

250×250

0.0016

0.0024

63

36.0

(74×74,33.6) 250×250 (63×63,36.0)

325×325

0.0014

0.0017

44

30.0

325×325 (44×44,30.0)

Table 9-5 S creens of S hale S hakers of Different Firms S TANDARD SQUARE

BAROID

BRANDT

DERRICK

IMCO

MILCHEM

S WACO

30x30

30x30

40x40

40x40

40x40

50x50

50x50

50x50

MILCHEM S WACO S30 30x30

30x30

B50

Dx38

30x30 60 Oblong

B60 40x40 50x50

50

S40 S50

Dx50

159

B80

80 Oblong

B100 60x60

80

80x80

100

100x100

100x100

S60

60x60

60x60

60x60

70x30

70x30

S80 B120 S100

120x120

C.

80x80 Dx100

80x80

80X40

Dx84

100x100

80x40 100x100

Dx100

120x120

100x100 120x120

Shale shaker applications. a)

Determination of screen mesh: Screen is recommended to use as fine as possible. When obvious solid plugging is observed or if only 50% or less screen area is covered with flowing mud, a finer screen must replace the coarser one. In general, solid particles

b)

larger than 74 μm are the portion to be eliminated by shale shakers; therefore a finest screen as 200 mesh can be applied when Gumble shale-like formations are drilled, a PDC bit is applied or ROP is low in a deep well.

c)

Number of shakers applied: The number of shakers applied in a rig is mainly determined by the ratio of the maximum mud circulating output of the rig and the treating capacity of a single shaker, usually 2 or 3 units on a rig. As a rule of thumb 75- 80 % of the total length of the screen should be covered by flowing mud and this may permit using the entire capacity of the shaker including consideration of dealing with mud surge.

d)

Arrangement of shakers. Serial arrangement: In this kind of arrangement, the coarse mesh shaker processes the fluid initially and the fine mesh shakers process the underflow of the precedent coarse one. Parallel arrangement: The shakers are arranged in a parallel mode and mud flows onto all the shakers through a distributor.

9.3.2 Hydrocyclones(水力旋流器) A. Classification. Hydrocyclones are divided in two categories (desanders and desilters). The specifications of hydrocyclones are shown in Table 9-6. Table 9-6 S pecifications of Desanders and Desilters

B.

Type of Hydrocyclone

Size,in

Capacity,gal/min

Cut Range,μm

Desanders

6-12

125-500

>44

Desilters

2-5

25-75

>8-10

Application of desanders and desilters. a) The cut point of 10 in or 12 in desanders is 40-45 m and that of 4 in and 5 in des ilters 20-5 m . Since desanders and desilters would discard large amount of barite along with the drilled solids in a weighted mud, therefore they are usually used only with unweighted mud. 2 in desilters can be optionally used for removing even finer particles (7-10 m ) of the underflow of the upstream desilters or mud cleaner. b) Number of hydrocyclones: the number of &sanders arranged in a set for a rig is 160

determined in the way that the capacity processed by the defined number of

C.

hydrocyclones of a set of desanders must be equal to 125 % of the maximum rig circulating rate or more. A number of hydrocyclones in a set of desilters must process 150 % of the rig maximum circulating rate. Factors influencing hydrocyclone performance. a)

Mud density.

b)

Solid content of the underflow of the preceding equipment or solid content of the mud

c) d)

that gets into the inlet of this unit. Mud viscosity. Feed pressure.

e) f)

Feed flow rate. Apex size.

g)

Cyclone performance: In order to make the hydrocyclones to work efficiently, the solid content of the underflow of the preceding equipment or that flows into the inlet of this unit must fit the unit itself. If this condition is satisfied, adjustment of feed rate, feed pressure or replacement of an apex of another size must be taken.

(a)

(b) Fig. 9-7 Hydrocyclone functioning states

(a) Cone-Spray underflow discharge; (b) Rope underflow discharge

"Cone Spray Discharge" and "Rope Discharge": When a hydrocyclone works in a high

161

performance efficiency, the discharged solids comes out from its underflow apex in a shape of so called "Cone Spray Discharge" mode. However cyclone underflow may appear very often as "Rope Discharge". "Rope Discharge" means poor cleaning efficiency and it can cause solids overloading of cyclone overflow, apex plugging and aggravated wear of vertex finder, overflow fitting, cone liners and rig pump parts meanwhile discard a big volume of mud. The reasons of the "Rope Discharge" to happen and the measures to revise it into "cone Spray Discharge" are as follows: a) Undersized apex: Enlarge apex size. b) Feed pressure is too low: Increase feed pressure. c) High mud viscosity: Dilution with water. d) High mud solid content: Dilute the inlet mud or run a higher number of cyclones. A sketch of hydrocyclone functioning states is shown in Fig. 9-7. The performance curves of different size hydrocyclones is shown in Fig. 9-8.

Fig. 9-8 Typical cyclone perfomance

As Fig. 9-8 shows, the 12 in hydrocyclone removes about 50 % of 44 μm solid particles contained in the fluid that enters into the feed inlet so as 44μm is called the CUT POINT, of the 12 in cyclone. In Table 9-7, the recommended feed pressures of hydrocyclones of some manufacturers are listed. Table 9-7 Recommended Hydrocyclone Feed Head Requirements(All Pressures Based on 9 lb/gal Mud) 2in P re

4in

He

Maunufactur

He Vol.gal/

ss

ad

psi

ft

35

75

e

5in

press

He Vol.gal/

press

ad min

psi

10in He Vol.gal/

press

ad min

psi

ft

12in He Vol.gal/

press

ad min

psi

ft

Vol.gal/ ad

min

psi

ft

min ft

Brandt-d 35

75

60

Sweco

35

75

50

Totco

35

75

60

45

96

75

rexel

Swaco

60

12

20

25

35

75

80

35

75

500

30

64

500

35

75

500

35

75

500

162

8 HV Pinneer

35

75

6in 80

35

75

100

35

75

80

35

75

500

35

75

375

std Baroid

35

75

50

Raroid 45

96

25

35

FSI

75

35

75

500

70

4in Involute

35

75

17.5

35

75

90

35

75

39

―H‖Type

Demco

Triflo

8in

35

75

75

35

75

65

35

75

140

Density difference between underflow and feed inlet of desanders and desilters (DUNF- Dfeed ), where Dunf represents mud density at underflow and Dfeed mud density at inlet, with a "Cone Spray Discharge":

Equipment

(D unf -D feed)

Desanders

2.50-5.00 lb/gal

Desilters

2.50-3.50 lb/gal

If the density difference is falling in the above range, the hydrocyclones can be considered working in the normal state. 9.3.3 Mud Cleaner(清洁器) A mud cleaner is introduced for treatment of weighted mud instead of desilters with the purpose of avoiding waste of barite. A mud cleaner is composed of a set of desilters (usually 4 in hydrocyclones) mounted above a fine mesh screen shaker (commonly 120-200 mesh, 117- 74μm) so that the underflow of the desilters can pass through the fine screen that discharges the solids larger than 74μm into reserve pit and lets its liquid containing a good part of barite pass through the screen and be conveyed into circulating system. Mud cleaner operation must be examined and adjusted frequently so loss of barite can be reduced. 9.3.4 Centrifuges(离心机) A.

Functions of centrifuges. Centrifuges are used to remove very fine solid particles (small down to 10 or 7 μm). Since

these fine particles affect mud rheological parameters in a much greater degree than the coarser particles therefore centrifuges can effectively control mud rheological properties and penetration rate in a favorable range by removing extra-fine particles. Besides this function, centrifuges are also applied for recovering barite while discarding fine particles from weighted mud. Centrifuges can treat only a part of the mud circulating rate (usually 10-20 % ) and they run usually with water dilution (20 -5 % ) for more efficient separation. B. Types of centrifuges. a) Decanting centrifuge: The decanting centrifuge is composed of a rotating bowl and a screw conveyor inside the bowl. The rotating bowl is a cylinder but with one end in the shape of a tapered section cone that favorites coarse solids separated to move to the discharge port. The bowl rotates creating high centrifugal force that throws coarse solid 163

particles on its inner wall and the screw conveyor rotates at a slightly slower speed pushing these coarse solid particles to the underflow discharge port. Meanwhile the liquid cleaned out of coarse solid particles and retaining the finer particles flows to the overflow discharge port. There are three types of decanting centrifuges: Barite Recovery Centrifuge, High Volume Centrifuge and High Speed Centrifuge(Table 9-8 ). Table 9-8

Operational Parameters of Varied Decanting Centrifuges

Type

GPM gal/min

RPM r/min

G-Force

Barite Recovery Centrifuge

14-40

1600-1800

500-700

Cut Point

m

6-10 for L.G.S 4-7 for L.G.S

High Volume Centrifuge

100-200

1900-2100

800

5-7

High Speed Centrifuge

40-120

2500-3300

1200-2100

2-5

b)

Rotary Mud Separator Centrifuge (RMS): The RMS centrifuge is composed of a stationary case and a perforated cylinder that revolves concentrically within the case at a defined speed. Mud and water is pumped protx)rtionally by two metering pumps into the annulus between the separator case and the cylinder. The condensed coarse solids are moved along the wall of the case and pushed out through the underflow port. The lighter liquid phase moves toward the center of the perforated cylinder and exits through the perforated rotating tube as overflow.

RIMS centrifuge has greater handling capacity and coarser discard than decanting centrifuge and its cut point depends on the geometry and mechanical design of the unit. The sketches of decanting centrifuge and RMS centrifuge can be seen in the following figures (Fig.9-9 and Fig. 9-10).

Fig. 9-9 Solid Bowl Decanting Centrifuge

Fig. 9-10 RM S centrifuge

164

1 -Stationary Case and Underflow, 2 -Rotor (Rotating Perforated Cylinder), 3 -Rotor Shaft-Perforated

C. Centrifuge applications. Centrifuge can be applied in the following modes. a) Recovering barite and removing ultra-fine and colloidal size solids in weighted mud with a single Barite Recovery Centrifuge. The liquid phase containing fine particles is discarded as overflow to reserve pit and the solids that contain a great percentage of barite are conveyed as underflow to the circulating mud system (Fig. 9-11). The purpose of this mode is to remove small colloidal particles from the mud in order to control mud viscosity. There is a large portion of mud discharged and wasted from overflow port in this operating mode.

Fig. 9-11 Recovering barite with a single Barite Recovery Centrifuge

b) Dual centrifuging for recovering barite and removing ultra- fine and colloidal size solids in weighted mud (Barite Recovery Centrifuge-High Speed Centrifuge Combination). The first Barite Recovery Centrifuge followed by a High Speed one are applied and work jointly. The solids predominantly barite from the underflow of the first Barite Recovery Centrifuge are recovered and introduced to the mud circulating system and the liquid phase retaining fine solid particles comes out from overflow port and is discharged to a small holding tank and then is pumped to feed the second centrifuge--High Speed Centrifuge. The solids separated by the second High Speed unit that come out from underflow port are discarded to the reserve pit and the cleaned liquid that comes out from overflow port is returned to the circulating system. The cleaned liquid separated by the High Speed Centrifuge can also b~ used to dilute the feed mud of the first unit--the Barite Recovery Centrifuge or dilute the recovered barite (Fig. 9-12). This dual centrifuging design is very cost effective when it is used on mud that contains precious liquids and chemicals.

165

Fig. 9-12 Dual centrifuging for barite recovery and removing ultra-fine particles

c) High Volume Centrifuge used for un-weighted mud to clean solid particles. The mud treated by upstream solids control equipment (shale shakers or hydrocyclones) is fed to the centrifuge. The solids removed by the centrifuge are discarded to the reserve pit and the cleaned liquid is returned to the circulating mud system. In this mode of centrifuge application, less mud dilution and haul-off can be achieved and the chemicals contained in mud can be saved (Fig.9-13).

Fig.9-13 Cleaning low density solids of unweighted mud with one High Volume Centrifuge

a)

Secondary recovery of hydrocyclone discharge: The under flow of the upstream hydrocyclones is fed to the feed inlet of a High Volume Centrifuge or a Barite Recovery Centrifuge. The solids separated in the underflow by the centrifuge are discarded to the reserve pit and the cleaned liquid is returned back in the mud circulating system or to the feed inlet of a High Speed Centrifuge for further cleaning (Fig.9-14). Benefits derived from this mode of application are less capacity of the reserve pit and less waste haul-off.

166

Fig.9-14 Secondary recovery of hydrocyclone discharge with centrifuge

b)

Water recovery from reserve pit. The mud from the reserve pit is fed to a High Speed Centrifuge for water recovery. The solids separated by the unit are discarded to a dump pit and the cleaned liquid is reverted to the circulating mud system or collected into a tank for further use (Fig. 9-15). This operation mode is usually applied in the areas where there is a difficulty of water supply.

Fig. 9-15 Water recoveries from reserve pit with centrifuge

9.4 Arrangement of Solids Control Equipment System(固控设备体系组合的原则) 9.4.1 Principles of Composing a Solids Control Equipment System A. Two or three shale shakers can be equipped in a drilling rig. The whole circulating mud must be treated by the running shakers and never allow whole mud or a part of it to bypass the shakers and be guided directly into hydrocyclones or centrifuges. The screen mesh should be chosen as fine as possible in order to create favorable conditions for the smooth and efficient running of desanders, desilters or centrifuges. B.

C.

The number and operational behaviors of the desanders should be carefully selected and adjusted so that they can clean completely the larger particles that are out of the processing range of the downstream desilters or mud cleaner. The capacity of centrifuges is small that represents only a part of the circulating mud. In order to make them work efficiently, they run usually with water dilution of the mud at their feed inlet all the time. The water addition percentage or so called dilution rate 167

is usually in the range from 20 % to 75 % depending mainly on the mud viscosity and solids content. A solids control equipment system, the separating capacity and the cut point of its components are shown in Fig. 9-16.

Fig.9-16 M inimum particle cut size and capacity of different solid control equipment

D.

Because desanders and desilters may discard barite, so they cannot be run when a weighted mud is applied for the purpose of avoiding barite loss.

High speed centrifuge

Centrifuge

2in Clone

M ud

RAM

M ud

RAM

M ud

Volu

weig

MUD

weig

MUD

weig

me

ht

VO;

ht

VO;

ht

Clone

D-Silter

D-Sander

EST SIZ E

Volu me

lb/ga

gal/mi

lb/ga

gal/m

lb/ga

gal/mi

gal/mi

l

n

l

in

l

n

8.5

90

8.5

40

8.5

25

1T4

150

9

75

9

38

9

25

2T4

300

EST SIZ E

n

me

11

40

for weighted mud systerms

M ico

Volu

on cut

me

m

n

2 2-1

3-1

gal/mi n

500

20  30

465

1000

1000

30  30

541

950

1500

30  40

381

900

10

36

10

25

4T4

600

11

34

11

15.7

6T4

900

40  36

300

800

12

31

12

11.4

8T4

1200

50  50

279

750

1500

60  60

234

700

80  60

178

600

140

400

117

250

104

200

10T

*Not designed

SIZE

gal/mi

2 64

EST

Volu

1-1

10

Screen

13

27

13

9

14

23

14

7.4

15

20

15

6.3

4

2

100  1 00

16

17

16

5.5

17

13

17

4.8

120  1 20 150  1

168

50 18

10

18

4.0

19

8

19

4.3

20

7

20

4.6

200  2 00

74

120

*Depends on the mud rheology

9.4.2 Commonly Used Solids Control Equipment Systems A. Conventional solid control equipment system for un-weighted mud (Fig. 9-17). B. Conventional solid control equipment system for weighted mud(Fig. 9-18).

Fig. 9-17 Arrangement of solid control equipment for unweighted mud

Fig. 9-18 Arrangement of solid control equipment for weighted mud

9.5 Evaluation of Efficiency of Solids Control Equipemnt(固控设备效率评价) 9.5.1 Calculation of Solids Separation Efficiency of One Unit from Solid Control Equipment System A. Calculation of low density solids separation efficiency of one unit: 169

E R LS 

VU  LS  QU VLS  Q

9-1

B. Calculation of barite separation efficiency of one unit:

ERB 

VU  B  QU VB  Q

9-2

Where, ER  LS --Low density solids separation efficiency of one unit from solid control equipment system, %,

VU LS --Low density solid content in the underflow of one unit from solid control equipment system (can be determined with retort), %,

Q U --Underflow volumetric rate of one unit from solid control equipment system (can be determined using stop watch pail method), gal/rain,

VLS --Low density solid content in the inlet of one unit from solid control equipment system (can be determined with retort), %,

Q --Inlet flow volumetric rate of one unit from solid control equipment system (can be read from flow-rate meter), gal/rain,

ER  B --Barite separation efficiency of one unit from solid control equipment system, %,

VU  B --Barite content in the underflow of one unit from solid control equipment system (can be determined with re tort), %,

VB --Barite content in the inlet of one unit from solid control equipment system (can be determined with retort), %. 9.5.2 Calculation of Drilled Solids Elimination Efficiency A.

Calculation of cuttings removing efficiency of the whole solid control equipment system:

ETRLS =

V1U  LS  Q1U  V2U  LS  Q2U  V3U  LS  Q3U  ... V TLS QT

9-3

Where, ETRLS --Cuttings removing efficiency of the whole solid control equipment system, %,

V1U LS ,V2U LS ,V3U LS ... —Low density solid content in the underflow of one unit from solid control equipment system,

%,

Q1U , Q2U , Q3U ... --Underflow rate volumetric of one unit from solid control equipment system, gal/rain,

170

V TLS --Low density solid content of mud at the well flowline (before shakers), %,

QT --Volumetric flow rate at well flowline (before shakers), gal/min. The procedure to determine the necessary data for conducting calculation of Equation 9-3 is very complicated. A simplified method of obtaining ETR-LS can be applied as follows:

ETRLS =

V BPS  LS VTLS

9-4

Where, V BPS  LS is low density solid content of the mud after the solid control system or before the pump suction, %. The results of ETRLS calculated from Equation 9-4 and Equation 9-3 can be compared. B.

Calculation of Cuttings removing efficiency of one unit from solid control equipment system:

 1  1.471 10

3

V1U  LS  Q1U D2 R

9-5

3) Calculation of cuttings removing efficiency of solid control equipment :

 T  1   2   3  . . . Where,

9-6

 1 -Cuttings removing efficiency of one unit from solid control equipment system, % Q1U --Underflow volumetric flow rate of one unit from solid control equipment system, gal/min

V1U  LS --Low density solid content at underflow of one unit from the solid control equipment system, % D --Hole diameter, in

R --Penetration rate, ft/h

 T --Cuttings removing efficiency of the whole solid control equipment system, % REMARKS:  The underflow of a shale shaker is referring to the cuttings with the mud adhered on and mixed with them over the screen cloth shaker. The overflow of a shale shaker is referring to the mud past through the screen cloth of the shaker. 

In case when Barite Recovery Centrifuge-High Speed Centrifuge Combination mode is applied, only the solid separation efficiency and the cuttings removing efficiency of the second centrifuge, the high speed one, is necessary to be calculated.

Example I: Hole diameter D = 12 1/4 in (Hole capacity CH = 0. 1458 bbl/ft), Penetration rate R = 8 ft/h. 1) Underflow volumetric rate Qu= 6 gal/min ( Qu= 360 gal/h). 2) Low density solid content at underflow VU LS = 12 %. 171

3) Barite content at underflow VU  B = 2 %. 4) Weight rate of low density solids at underflow

QW U  LS V U  LS  DS  8.33  360 12%  2.6  8.33  933 .12lb / h . 5) Weight rate of barite at underflow

QW U B  360  2%  4.2  8.33  252lb / h . 6) Weight rate of total solids at underflow

QW U  QW U LS  QW U B  933.12  252  1185 .12lb / h 7) Weight generation rate of drilled cuttings of the well

QW GEN  350C H  R   DS  350  0.1458  8  2.6  1061 .4lb / h 8) Cuttings removing efficiency of this unit of solid control equipment

1  1.471  103  12  6  (9.625 2  10)  88.0% Example II: D = 9 5/8 in (Hole capacity CH =0.0900 bbl/ft), RP EN = 10 ft/h. 1) QU = 4 gallons per minute = 240 gallons per hour. 2) VU  B = 12 %. 3) VU  B = 2 %. 4) QW U  LS = 240  12 %  21.6 = 622.08 lb/h. 5) QW U  B = 240  2 %  35.0 = 1681b/h. 6) QW U =622.08+168 = 790.08 lb/h. 7) QW GEN --- 350  0.0900  10  2.6 = 819 lb/h. 8)

 1 -- 1.471  103  12 4  (9.6252  10) = 76.2 %.

Nomenclature:

DUNF --Mud density at underflow of a hydrocyclone, lb/gal. DFEED --Mud density at inlet of a hydrocyclone, lb/gal. ERLS --Low density solids separation efficiency of one unit of solid control equipment system, %.

VU LS --Low density solid content at underflow of one unit in solid control equipment s ystem, %. 172

QU --Underflow rate of one unit in solid control equipment system, gal/min. VLS --Low density solid content at the inlet of one unit in solid control equipment system (can be determined with retort),%.

Q --Inlet flow rate of one unit in solid control equipment system, gal/min.

ER B --Barite separation efficiency of one unit in the solid control equipment system, %.

VU B --Barite content in the underflow of one unit in solid control equipment system, %. VB --Barite content in the inlet of one unit in solid control equipment system, %. ETRLS --Cuttings removing efficiency of the whole solid control equipment system, %. V1RLS , V2 RLS , V3RLS ,... --Low density solid content of one unit from solid control equipment system, %.

Q1U , Q2U , Q3U ... --Underflow rate of one unit from solid control equipment system, gal/min. VTLS .. --Low density solid content of mud at the well flowline (before shakers), %. QT . --Flow rate at well flowline (before shakers), gal/min.

VBPS LS .. --Low density solid content of the mud at the downstream after the solid control equipment system or before the mud pump suction, %.

 1 ---Cuttings removing efficiency of one unit from solid control equipment system, %. Q1U --Underflow volumetric flow rate of one unit from solid con trol equipment system, gal/min. V1U LS --Low --density solid content at underflow of one unit from solid control equipment system, %. D --Hole diameter, in.

R --Penetration rate, ft/h.

 T ---Cuttings removing efficiency of the whole solid control equipment system, %.  DS --Density of low density solids, g/cm3.  B --Density of barite, g/cra3. C H --Hole capacity, bbl/ft.

173

QW U LS --Flow weight rate of low density solids at underflow, lb/h. QW U  B --Flow weight rate of barite at underflow, lb/h. QW U -- low weight rate of total solids at underflow, ib/h. QW GEN --Generation weight rate of drilled cuttings of the well, lb/h.

174

CHAPTER 10 THE NEW DRILLING FLUID TECHNOLOGY 10.1 Silicate Drilling Fluid(硅酸盐钻井液) In the mid-1990’s, there was increasing pressure to find a high performance water-based drilling fluid that would be an environmentally acceptable alternative to oil-based drilling fluids. Since the 1930’s, it has been known that silicate-based drilling fluids provide oil-like shale stability. Aside from containing sodium or potassium silicate(硅酸 钠或硅 酸钾 ), current silicate-based drilling fluids would have little in common with these early fluids. Advances in formulating chemistry have made silicate-based drilling fluids an effective, versatile and low cost alternative to oil-based drilling fluids. Since their re-introduction in the North Sea, silicate-based drilling fluids have steadily gained in popularity with service and oil companies. Drilling fluid using sodium and potassium silicates, offers the flexibility and versatility to design a mud system for almost any drilling environment and provides: A. superior well bore stability B. superior environmental performance C. excellent ROP’s D. low depletion rates E. corrosion control F. improved cementing 10.1.1 The Soluble Silicates(可溶性硅酸盐) Soluble silicates are manufactured by fusing sand (SiO 2 ) with sodium or potassium carbonate (K2 CO3 or Na2 CO3 ) in an open hearth furnace at 1100-1200℃ and then dissolving the glass using high pressure steam forming a clear, slightly viscous liquid known as ―waterglass.‖ Liquid silicate is the most popular commercial form of soluble silicates used in drilling fluids. However, liquid silicates can be spray-dried to form quick-dissolving hydrous powders. When conditions warrant, such as limited storage on off-shore rigs, long hauling distances or extended exposure to sub-zero temperatures, hydrous powders can offer a cost effective alternative to liquid silicates. One of the key parameters that determines the properties of soluble silicate solutions is the weight ratio（重量比） of SiO2:Na2 O. For example, a ―2.0‖ ratio silicate has 2kgs of SiO2 for every 1kg of Na2 O. The molecular weight of SiO2 and Na2 O are so close that the molar(模数) and weight ratios are said to be the same for all sodium s ilicate products. However, it should be noted that the molar and weight ratios for potassium silicates differ significantly. In terms of silicate anion structure and relative concentration, liquid silicates with higher ratios will contain proportionately greater levels of condensed, complex species with higher molecular weights. Similarly, the low and mid ratio liquids will contain significant levels of low molecular weight chains and cyclics as well as free monosilicate. These changes in silicate speciation can have a measurable impact on drilling fluid rheology, shale inhibition and overall mud stability. Ratio selection is therefore an important consideration in formulating silicate drilling fluids. 10.1.2 Chemistry Advantage of Silicate(硅酸盐的化学优势) Drilling fluids using silicate products are known for providing superior well bore stability. 175

In-gauge holes are achieved through a unique combination of versatile chemical reactions; most notably gelation(胶凝) and/or precipitation（沉淀） on shale surfaces. Gelation is the self-polymerization（聚合） or condensation（缩合） of soluble silicate structures to form a hydrous, amorphous gel structure of silicate. Gelation is brought on by a drop in pH with polymerization beginning to rapidly occur at pH below 10.5. Precipitation of silicate is the cross-linking of silicate molecules by multivalent cations (i.e. +2

+2

+3

+3

Ca , Mg , Al , Fe , etc). It is generally believed that as the silicate in the mud comes into contact with the slightly acidic (pH 6-8) and multivalent-rich pore water, a localized gelation reaction, coupled with a minor amount of precipitation, takes place to block both the influx of mud and pressure into the formation. These reactions also lead to the sealing of microfractures, cracks and rubble giving a silicate drilling fluid a decided advantage over any oil mud, significantly reducing potential mud losses and costs. These unique gelation and/or precipitation mechanisms also make a silicate drilling fluid a natural fluid loss agent so there is little transfer of fluids and pressure into the formation, keeping the integrity of the wellbore intact. In addition to this unique chemistry, silicate drilling fluids provide a thin, tough, ultra low permeable filter cake significantly reducing drilling problems such as differential sticking or torque & drag, while providing improved cementing. The formulations of silicate drilling fluids are proven performers in all parts of the world in a variety of drilling environments. Whether drilling in the North Sea, the Middle East, the North American Rockies, Mexico or South America, silicate drilling fluids help deliver an in-gauge hole. 10.1.3 The other Advantages of Silicate(硅酸盐的其他优点) ROP enhancement. Field results from around the world demonstrate that silicate based drilling fluids have ROP’s that favorably compare to any drilling fluid, including oil based muds. The high penetration rates are attributed to its excellent inhibitive properties, which prevent drill solids from being easily dispersed into the drilling fluid. It is not uncommon for a silicate mud to maintain its initial density throughout drilling. A silicate drilling fluid’s ability to inhibit also means very little reaming, leading to little or no downtime. Runnability. A silicate drilling fluid is an extremely easy system to run. The muds with it are easy to maintain with very slow and predictable depletion rates, and because they typically contain fewer components making handling and logistics easier. Rheology tends to be unaffected by changing mud conditions. Monitoring the fluid condition is easy- a simple check every 24 hours will ensure optimum down hole performance. Safety. Sodium and potassium silicates are considered one of the most benign industrial chemicals in use today. In fact, the pH of silicates is very similar to liquid dishwashing detergent. Cost. With exceptional performance in the field, the silicate muds are proving to be a cost effective alternative to oil-based drilling fluids as well as other high performance water-based drilling fluids, for the above advantages. Environment. Silicates are one of the few oil field chemicals that can be beneficial to the environment. Soluble silicates are derived from, and ultimately return to nature, as silica (SiO 2 ) and soluble sodium and potassium compounds. Since these are among the earth’s most common chemical components, they offer little potential for harmful environmental effects.

176

10.2 Mixed Metal Hydroxide(正电胶钻井液) Mixed metal layered hydroxide compounds (MMLHC) mud-MMH mud has a low environmental impact and has been used extensively around the world in many situations: horizontal and short-radius wells, unconsolidated or depleted sandstone, high-temperature, unstable shales, and wells with severe lost circulation. Its principal benefit is excellent hole-cleaning properties.

Fig. 10-1 Schematic of the structure of MM H

Mixed metal layered hydroxide compounds are inorganic materials which are made up of discreet layers, consisting of two or more metal ions surrounded by hydroxide ions. Its formula is 2

3

x

n

described as [ M1 x M x (OH ) 2 ] Ax / n  mH 2O , where, M2+ can be Mg2+, Mn2+, Fe2+, Co2+, Ni2+, Cu2+, Zn2+, etc., M3+ can be Al3+ , Cr3+ , Mn3+ , Fe3+ , Co3+ , Ni3+ , La3+ , , etc.. A can be Cl-, OH-, NO3 -, etc. Due to symmetry considerations, there is not enough room in the unit cell to accommodate a stoichiometric number of hydroxide ions. Thus, the sheets are electron deficient and a crystallographic positive charge is generated, Figure 10-1 and Figure 10-2. Because the positive charge must be balanced by anions in order to achieve electrical neutrality, anions associate with the basal plane of the crystallite. The surface interacts with these anions through an ion exchange mechanism, similar to that of anion exchange resin or clay mineral.

Fig. 10-2 Crystal Structure of MM H

MMH mud is based on an insoluble, inorganic, crystalline compound containing two or more metals in a hydroxide lattice-usually mixed aluminum/magnesium hydroxide, which is 177

oxygen-deficient. When added to prehydrated bentonite, the positively charged MMH particles interact with the negatively charged clays forming a strong complex that behaves like an elastic solid when at rest. This gives the fluid its unusual rheology: an exceptionally low plastic viscosity-yield point ration. Conventional muds with high gel strength usually require high energy to initiate circulation, generating pressure surges in the annulus once flow has been established. Although MMH has great gel strength at rest, the structure is easily broken. So it can be transformed into a low-viscosity fluid that does not induce significant friction losses during circulation and gives good hole cleaning at low pump rates even in high-angle wells. Yet within microseconds of the pumps being turned off, high gel strength develops, preventing solids from settling. There are some indications that MMH also provides chemical shale inhibition. This effect is difficult to demonstrate in the laboratory, but there is evidence that static layer of mud forms adjacent to the rock face and helps prevent mechanical damage to the formation caused by fast flowing mud and cuttings, controlling washouts. MMH is a special fluid sensitive to many traditional mud additives and some drilling contaminants. It therefore benefits from the careful management that is vital for all types of drilling fluid. 10.3 Polyol Technology Systems(聚合醇钻井液) Polyol is the generic name for a wide class of chemic als including glycerol(丙三醇), polyglycerol(聚丙三醇), glycols（乙二醇）and propylene glycol（丙二醇）. In drilling fluid, one type of them can be used individually or two or more of them in combination. Polyglycol(聚 乙 二 醇 ) is the most extensively used one. Glycol appears as a sticky milk-like white, water-soluble liquid and is reciprocally miscible（混合） with water at lower temperature. The water solubility of glycol decreases as temperature increases. The temperature at which glycol and water separate is known as the "cloud point"（浊点）, because, at this point the previously clear solution becomes cloudy, see figure 10-3.

Fig. 10-3 Cloud point

Once the entire solution temperature has risen above the cloud point, two distinct phases 178

become visible. The clouding process is reversible. When the solution cools, the glycol and water recombine to form a clear, single phase. Four factors control the cloud point: A. polyol type B. polyol concentration C. salt type D.

salt concentration

Cloud point plays a critical role in the glycol drilling fluid system’s improving shale stabilization. There is an instantaneous reaction whenever the fluid contacts a shale with a temperature exceeding that of the system’s cloud point. The glycol drops out of solution and attaches to the ―hot‖ shale. This protective layer prevents the shale from interacting with the water, minimizing swelling. 10.4 Micro-bubble (Aphron) Drilling Fluid(可循环微泡沫钻井液) 10.4.1 The Structure and Stability of Mircro-Bubbles Fig.10-4 shows the structure of a gas aphron at the molecular level. The aphron is usually composed of a gas core and a more complex soapy shell, which has an inner as well as an outer surface with a sheath of viscous water between them. This shell has oriented surfactant molecules at the outer surface that are hydrophilic group pointing inwards and hydrophobe outwards, which means that aphrons possess some hydrophobic/lipophilic character. Between this soapy shell and bulk water there is an interface, and, according to Gibbs adsorption isotherm, there must be a higher concentration of surfactant at that surface than in the interior of the bulk water. This surfactant is hydrophobe facing the soapy shell and hydrophile the bulk water, with which the aphrons are compatible with the continuous aqueous phase. The outermost surfactant layer tends to be shed when mircrobubbles come in contact with each other.

Fig. 10-4

Structure of a gas aphron

This soapy shell is of viscosified water with a certain minimum thickness, which is sufficiently strong and impermeable that it resists compression and suppresses transport of air to the aqueous environment. 10.4.2 Energized Micro-Environment of Aphron Structure and Bubble Flow Fig.10-5 illustrates the aphron energizing process. An aphron, which has a diameter of 96 microns at the 0.1 MPa surface pressures, is compressed into a smaller one with 16 micron diameter at 21.89 MPa. Owing to the tough and impermeable viscous water shell, the air in the core survives and does not achieve the small size expected from compression, with which an 179

―energized environment‖ is created. Aphrons tend to cream or to flow faster than the bulk water. Sebba1 indicated that the less dense gas bubbles rise to the surface owing to their being much lighter than the bulk water in which are dispersed. Growcock3 observed ―bubble flow‖ by a test of a Radial Flow Cell filled with 2-mm glass beads and red-dyed water. Aphrons containing blue dye was pumped by the ―bore hole‖ of the cell at a pressure of 70 kPa, allowing invasion of aphrons into the cell. As shown in Fig. 10-6, a white band of bubble flow (about 3 cm) formed almost immediately between the two fluids. 10.4.3 Bridging Mechanism in a Loss Zone In water-wet reservoirs, capillary pressure resists intrusion of hydrophobic micro-bubbles into capillary restrictions in the formation, Fig.10-7. Gardescu showed that the capillary pressure, or resistance, that is offered to fluid displacement by Fig.

10-5

The

aphron

a bubble of non-wetting fluid, when squeezed from its original radius to the constriction radius, can be described by the

following energizingexpression: process

p  2 (1/ r1  1/ r2 ) Where, p is capillary pressure (resistance),

 is interfacial tension, r1 is capillary radius,

r2 is original radius. Although p is very small for a single bubble, Jamin showed that the cumulative resistance of many bubbles in a capillary restriction may be large. It is highly unlikely that pressure gradients of sufficient magnitude could be applied in the field to overcome this ―Jamin Effect‖ and force deep penetration of aphrons into the interconnected openings in permeable formations. The effectiveness of the seal formed by aphrons is dependent on the size of the opening and the degree of hydrophobicity of the micro-bubble shell.

Fig.10-6 Bubble flow of aphrons

Fig.10-7 Capillary pressure

180

Fig. 10-8 When aphrons are driven into a low-pressure, they expand and aggregate to form a seal.

10.5 Formate Drilling Fluid（甲酸盐钻井液） The industry’s changing and so are the drilling and completion fluids. Facing HTHP environments, horizontal and extended reach drilling, slim-hole and coiled tube applications, and generally much tougher challenges than fifty or even twenty years ago. Add to that the fast pace of change that typifies environmental and safety legislation, and it’s a whole new world– one demanding a whole new fluid. The formate drilling fluids posses the following advantages: A.

No weighting materials means no sag, improved ECDs (Equivalent Circulating Dens ities) and better overall circulation rates

B.

High compatibility with reservoir fluids and minerals maximises reservoir protection and improves well productivity Extremely versatile fluids used in all phases of drilling and completion eliminate the costs of fluid change

C. D.

Optimised hydraulic flow maximises power transmission, facilitates hole cleaning and

E. F. G.

increases ROP (Rate of Penetration) Alkaline properties give outstanding corrosion protection Stabilises shales and enhances borehole stability Improves well control and allows faster tripping

H. I.

Excellent compatibility with elastomers and polymers Facilitates faster and more accurate logging – even with extended reach drilling

J. Best environmental and safety profile of all drilling and completion fluids 10.5.1 Formates(甲酸盐) Formates are a class of salt originating from formic acid, an organic substance found in nature, including trees, plants, fruit and berries. The three formate bases – cesium, potassium and sodium – used for drilling, completion, workover and fracturing fluids are common in the modern world, with applications as diverse as de-icing fluids and cosmetics to animal feeds and preservatives. These three cations naturally occur in the world’s oceans. Sodium and potassium are the second and sixth most abundant elements respectively, while cesium is surprisingly common at 29th place. Formates have the following features as drilling fluids : A.

Formate is safe for the environment and crew.

B.

Recycling cuts fluid costs by reclaiming formate and using them in multiple wells. 181

C.

Naturally weighted. Formate brine drilling fluids are naturally weighted, monovalent fluids 3

3

with a maximum density of 2.30g/cm (19.10 ppg) for cesium formate, 1.57 g/cm (13.05 ppg) for potassium formate and 1.30 g/cm3 (10.85 ppg) for sodium formate. The graph shows the freezing and crystallisation profiles for the three brines.

10.5.2 Formate Drilling Fluid and Its Properties Potassium, sodium or cesium formate can be used individually or two or three of them in combination to form a solution with a preferable density. The density of formate drilling fluid can be adjusted in the range of 1.60- 2.30 g/cm3 by selecting type of formate solution and weighting with acid soluble weighting materials such as carbonate CaCO 3 or hematite Fe2 O3. When the concentration of potassium formate (density of potassium formate 1.90 g/cm 3) is 35%, the density of formate drilling fluid system is about 1.60 g/cm3. Sodium formate is cheaper and potassium formate is more expensive and cesium formate is the most expensive. An adequate amount of viscosifier, FL control agent, lubricant and defoamer are concurrently used in the fluid for obtaining a system with satisfactory properties. This system is characterized by its excellent stabilizing capacity and evidently reduced formation damage. High cost and enormous quantity of formate required limit the application range of this system. To achieve the required fluid loss and rheology, formate drilling fluids are formulated for use to at least 166°C (330°F) using common oilfield polymers. Uniquely, formate mud properties are almost completely independent of density, so rheology and filter cake thickness do not change between 1.20 g/cm3 (10.00 ppg) and 2.20 g/cm3 (18.30 ppg). The example formulations below are ideal for reservoir drilling where low yield points combine with good circulation rates to provide adequate hole cleaning. Should a higher rheology be required, the level of Xanthan is increased, as the 1.40 g/cm3 (11.70 ppg) formulation demonstrates. Even with such a low level of solids and temperatures of 149°C (300°F), the HTHP fluid loss (including spurt loss) is extremely low and filter cakes become so thin they are transparent. Stable formulations, using HTHP polymers, are made for temperatures up to a minimum of 204°C (400°F). No sag, no problem. No weighting agent means no sag, and no sag means the elimination of a

whole pile of problems, from additional hours circulating and conditioning muds to serious well control incidents. Sag is at its worst in deviated wells. Consider a 6- or 81/2-inch hole drilled at 45°. Here, particles need to drop only an inch or two before the density differential between mud layers causes an avalanche. The time window for this to occur is a matter of hours, rather than days, resulting in compromised well control and other problems. According to Stokes’ Law, API barite with a P50 particle size of 5 microns will fall one inch in 20 seconds. Grinding the barite much finer to an average size of, say, one micron, may reduce settlement rate, but in this case only to 5.6 hours per inch – a very short time when settlement of a few inches is the margin between success and failure, as the diagram below shows. More efficient screening. Solids-free formate brines are dream fluids when it comes to

screening drill cuttings. With traditional fluids, the drilling crew must create a balance between screening out drill solids and retaining the weighting agent. Either way it’s a compromise. With formate brines, the lack of solids means finer screens and increased flow rates are easily achieved.

182

A typical example is a HTHP well in the North Sea drilled with formate brines. Here, 325 and 400 3

mesh shaker screens were run successfully using 1.62 g/cm (13.50 ppg) mud. 10.6 Non-Invasive Drilling Fluid（无侵害钻井液） 10.6.1 Introduction SM

No-damage drilling is the ultimate goal of all well construction activities, a way to explore and produce the hydrocarbon reserves with minimum reduction of natural permeability of the reservoir rocks. Conventional drilling is conducted with an over-balanced pressure on the reservoir formation, which causes the drilling fluid to invade and damage the rock. In order to overcome the problem of formation while drilling, a method was developed to drill with a bottomhole pressure below the pore pressure, called Underbalanced Drilling-UBD. The development and recent increase in UBD activity is due to the understanding that there will be no formation damage if a reservoir is drilled underbalanced. UBD is, most probably, still the best way to achieve no-damage drillingS M. However, the big problem associated with UBD is how to guarantee that no overbalance periods will happen while drilling or completing the well. Also, there are many situations in which technically it is not possible to have an underbalanced pressure kept at all times. Just a small period of overbalance may cause damaging filtrate invasion. Most of the UBD operations are carried out by injecting gas to reduce the hydrostatic pressure inside the wellbore, and, therefore, producing an underbanlanced condition at the bottom of the well. The gas injection creates a complication due to multi-phase flow is that the bottom hole pressure oscillation, sometimes significantly. This bottom hole pressure oscillation becomes one more variable difficult to ensure an underbalanced condition at the bottom of the hole at all times, even if the well is flowing (oil and /or gas). For example, there is no guarantee that the entire extension of the reservoir can be subjected to an underbalanced condition at all times, this is especially critical in horizontal wells, with long open hole sections. Another big problem concern when planning a UBD well is to check the potential for wellbore instability. With the popularity of UBD, the industry has become much more aware of the importance of delivering a non-damaging well, regardless of the way the well drilled. In cases UBD is not used, a drilling fluid with an SM overbalanced pressure should be used. The goal of the no-damage drilling approach is to deliver a close to zero-damage well, in all circumstances. A new drilling fluid called non-invasive fluid SM

- NIFSM has been developed and in the market to fill this gap. This technology has been tested and approved for more than 13 years in various parts of the world, demonstrating that it can stop the losses and prevent fluid invasion, even in very adverse conditions, where all other products failed to succeed. 10.6.2 Comparison with traditional drilling fluids The most common procedure today is to add particles in the fluid to bridge the pore throats. The commonly used particles are calcium carbonate and salt, due to the fact that even if they cannot be removed, an acidification job or dissolution with water would eventually remove the damage created. The bridging approach requires the particles to penetrate into the rock, and find a suitable pore size, according to the particle size distribution in the fluid the moment drilling is happening, to be able to bridge it and avoid further penetration. If, by any reason, this adequate size is not found, the fluid will not bridge effectively, and the fluid will penetrate deep into the rock. 183

By just circulation the fluid, the particle sizes are changing constantly, due to friction inside and outside the borehole. Depending on how soft the solids are, the particle sizes will be affected more rapidly or more slowly. Two main disadvantages of the bridging approach to seal the permeable formation can be detected: first, it is extremely difficult to exactly define the actual pore size distribution of the rock to be drilled. Second, it is hard to believe that the open hole section will contain a very homogeneous rock, with very small variation in the pore size distribution to be expected. The consequence of this is a complete inability of the fluid originally used to continue sealing the rock being exposed as drilling progresses. Many operators have experienced this problem, with seepage losses being observed. In these cases, more calcium carbonate is added, and eventually the losses are reduced. If the losses are not completely stopped, it means that the fluid is invading the rock continually. The big problem here is that the fluid invading the rock contains a significant amount of s olids in its composition, and, by deeply invading the rock, the damage caused will be virtually impossible to be removed, even with acidification. Ac idification treatments are not effective if the damage is deeper than a certain value, which is certainly the case when seepage losses are experienced and cannot be controlled. Maintenance of the NIF SM is extremely easy. Addition of the fluid loss controller additive, FLC2000, is enough to maintain the sealing effectively. And the amount required is dictated by a test conducted against a sand bed. If the sealing is not effective, addition of more FLC2000, is needed. SM

10.6.3 Characteristics of NIF

With conventional mud the filtrate invades as a function of the square root of time; on the other hand, with the new NIFSM fluids the filtrate invas ion is limited, and does not continually invade. This is a different approach from all traditional fluids available. SM

The NIF is a new class of drilling fluid, with ultra-low solids content, less than 10 ppb. Its sealing action uses a unique surface chemistry principle, producing a thin and impermeable membrane at the face of the formation. Contrary to the traditional approach of bridging the formation, the NIF SM seals the formation by the attraction force of the particles inside the fluid, concentrating them at the surface of the rock as the fluid is forced to invade it due to the overbalanced pressure. This characteristic allows it to seal formations of different pore size distributions with the same fluid composition. The sealing membrane can be removed by acidizing operation or flushed away by oil flow when the well is brought into production (98-99% according to the lab tests)and about 95% original formation permeability can be restored. The characteristics of this fluid are its capacity to build up a sealing membrane of certain strength into certain thickness of the formations around the borehole by addition of special polymer type additives into a water base or oil base drilling fluid. This sealing membrane can block the connection paths between the borehole and the formations, make the formations be not contacted with the drilling fluid, isolate the pressure system of formations from that of the drilling fluid therefore the productive zones can be effectively protected from damage meanwhile lost circulation can be easily avoided or treated. The borehole stability can be ensured by taking away the shale hydration environment; the frequency of differential sticking and blowout can be greatly reduced; and the drilling operations can be safely and smoothly conducted. The main advantages of the NIFS M are the following: A. Totally friendly to the environment

184

B.

Effective sealing of hetergenneous permeable formation with the same fluid composition

C. D. E. F.

Allows increase of the leak-off pressure Widens a narrow mud weight window Seals permeable formation and micro-crack in shale Can drill the overburden and the reservoir with the same fluid, including completion

G. Reduced transport and storage costs By effectively sealing against a permeable formation while drilling, the NIF

SM

develops what

SM

is called Virtual casing . The consequences of this action are: A. Reduction of differential stuck pipe risk B. Reduction of fluid losses, virtually eliminating them C. D.

Reduction of wellbore instability problems Reduction formation damage

The important point here is to show how the sealing membrance is removed. 10.6.4 The components of NIFS M The fluid is composed of basically three components: 3

A. DWC2000, a viscosifier; (max dosage 30 kg/m ) B. FLC2000, a dynamic fluid loss reducer (not for reduction of API filtrate)(routine dosage 3

6-12 kg/m ); and 3 C. KFA2000(dosage range 20-300 kg/m ), a lubricant, The three additives are of one-sack type and can be used individually or in combination and the formulation must be determined by pilot tests. A fourth product, LCP2000, is the material to be used when severe losses are encountered, when drilling formations with fractures and vulgs, for example. It should be kept as contingency and used immediately to restore circulation in severe case. In addition to these products, the final fluid should have a PH around 10, salinity as desired to inhibit shales (any kind of salt and any concentration can be used, even formats), and weight material as needed ,barite or hematite. As the sealing membrane is located at the rock face, without penetrating deep into the rock, with around 1 mm thickness, just by removing the overbalanced pressure against the rock the effectiveness of the sealing membrane is gone. Then, by just flowing in the other direction the membrane is removed, with extremely small resistance. The present Chinese additives of NIF system are JYW-1 and JYW-2 and the latter is for high permeability formations. 10.6.5 The mechanism of NIFSM FLC2000, a dynamic fluid loss reducer, is a blend of polymers modified to provide components with a range of

Fig.10-9 A schematic representation of the modified polymers . (1) forming micelles (2) in solution. The micelles form the low permeability, deformable barrier (3) on the rock surface in the very early stages of mud filtration

water and oil solubilities (i.e. the blend contains polymers with a wide range of HLB values). When added to a

185

water-based fluid, some of the polymers in the blend dissolve to provide fluid loss control similar to many conventional additives. However, other species only partially solvate because of their oil-loving characteristics; these polymers organize into deformable aggregates or micelles (micelles are assemblages of molecules that group together in solution to form microscopic spheres, rods and plates in solution). It is claimed that these micelles have the ability to form rapidly a low permeability seal over pore throats and microfractures, thereby greatly limiting fluid invasion. When driven by the fluid overbalance, the fluid starts to invade a permeable rock and these micelles rapidly form a low permeability seal over pore throats, thereby greatly limiting further fluid invasion. The micelles in the layer are deformable so, as the pressure is raised, they compress and reduce the barrier permeability even further. The mechanism is depicted in Fig.10-8. Particle size analysis (Fig.10-10) suggests that the micelles range from a few microns to close to 1000 microns in diameter (the d50 is around 60 microns, the d10 is 9 microns and the d90 340 microns). The material provides excellent invasion control by quickly forming a very low permeability layer rich in micelles. This greatly reduces any further ingress of solids or fluid. The micelles in the layer are deformable so, if the pressure is raised, they compress and reduce the barrier permeability even further.

Fig.10-10 Particle size distribution of the micelle-forming additive in water

In some respects, the micelles act like the water droplets in invert emulsion oil muds; these water droplets are known to concentrate in the filter cake where they make a major contribution to the invasion control seen with oil muds. The major difference, and benefit, of the micelles is that they are more deformable and cover a much wider size range; hence they are better sealing agents and work over a much wider range of pore sizes and permeabilities. Because of the range of oil and water solubilities in the blend, the additive works equally well in oil- and syntheticbased muds as in water-based; in hydrocarbon fluids, the oil soluble components dissolve instead of forming micelles while the water-soluble entities form the micelles – a reversal of the roles in a water mud. By functioning as a very low permeability barrier, the additive has the ability to protect weak formations against pressure transmission and fracturing. This effective increase in fracture gradient widens the safe drilling window and has great potential for improving drilling performance, not only in microfractured formations but also in depleted zones, unconsolidated

186

sands, etc. Cleanup of the protective barrier in reservoir applications is simple, because the micelles only exist above a critical concentration of polymers in the fluid. Therefore when contacted by a washing fluid or completion brine free of the polymers, or when contacted by reservoir fluid as the well is brought on production, the layer simply disperses and is removed in the wellbore fluid. Effective concentrations are between 3 and 8ppb. The optimum within this range depends on the base fluid properties and the permeability of the formations being drilled (e.g. higher concentrations would typically be required to protect very permeable formations and to give good invasion control in low solids fluids and in high salinity brines). 10.6.6 Application SM

With all these benefits, the NIF is applicable to many situations while drilling, not just to drill the reservoir section without damage but also to deal with these cases: A. B.

Reservoir interbedded with shales Reservoir with different pressure exposed in the same open hole section

C.

Severe wellbore instability problems due to mechanical causes (high tectonic stresses,

D.

for example) Narrow mud weight window

10.7 High-performance Water-Based Drilling Fluid-Polymeric Amine Drilling Fluid (HPWBM-聚胺钻井液) 10.7.1 Introduction As fields mature and the search for new oil and gas reserves continues, operators on the whole are increasingly moving towards drilling more challenging well profiles. Typical well profiles ever more frequently present challenges such as extremes of drilled depth, temperature, pressure, horizontal step out and extreme water depth to name but a few. In most cases, the common drilling problems found in less complex wells are usually exacerbated by increased complexity of well design. Conventional WBM is often excluded from consideration in challenging wells to the technical shortfalls associated with these problems. To address the drilling problems associated with shale instability various non-aqueous fluids (NADF) such as mineral oils, saturated and unsaturated polyalpha olefins and esters have been developed and utilized in the field. Along with the shale stability benefits of these NADF, various other benefits like lubricity, temperature stability, and anti-accretion are attributed to NADF. Along with those advantages, NADF have disadvantages, such as high cost, environmental limitations, disposal problems, health and safety issues and detrimental effects on the drilling and completion of the pay zone. Consequently, a water-based drilling fluid which performs like an oil-based mud has been an ambitious goal of the drilling industry. A HPWBM can become an attractive alternative option. Two characteristics of the HPWBM have been identified that contribute significantly to performance of the drilling fluid-shale stabilization and lubricity properties. These OBM characteristics serve as design targets to many researchers of aqueous-based systems striving to achieve the performance of OBM system when using a WBM. A high performance water-based mud (HPWMB-also called amine base drilling fluid) 187

containing clay and shale stabilizers, a ROP enhancer, and sealing agents was developed to drill the well, being found a wide application in overseas petroleum exploration and development, and is taken as the substitution for oil base mud. This mud was classified as a new drilling fluid in 2006. The high performance drilling fluids use a new cationic polymer—ether/glycol polyamine as shale inhibitor. This amine salt has a high inhibitive and bit balling prevention capacity, and is environmentally friendly. The high performance mud functions like an oil base mud because of its filming ability. Potassium normally in chloride salt form was added to drilling fluids and was found to be effective shale inhibition for swelling clays. This has become the starting point for the evolution of some exotic salts as well as ammonium and amine-based chemistry for shale inhibition in high performance water based mud. 10.7.2 Evolution of Nitrogen-based shale inhibitors It has been a long history for amine/ammonium salts to be shale inhibitor. Its process is about: Ammonium Chloride → Ammonium Salt mud Systems → Organic Cationic Materials → Quaternary Cationic Polymers → (PHPA-Partially Hydrolyzed Polyacrylamide) → Quaternary Alkyl-Amine →Quaternary Hydroxyl Amines) → Amphoteric →Alkyl-Diamines→Polyamine Glycols → Ether/Glycol Polyamines.

Poly-amine

Ac ids

10.7.3 Characteristics and Mechanism of HPWBM The laboratory results and field tests reveal that HPWBM drilling fluid system significantly reduces clay dispersion, hydration, and accretion outperforming previously developed inhibitive WBM systems and reaching into the performance territory of OBM. The dispersion and lubricity testing show that the inhibitive performance of newly developed HPWBM performed very close to OBM. The new HPWBM has been designed with a total system approach. Products have been chosen to satisfy the requirements of performance of OBM such as high inhibition, nondispersive, antiaccretion and superior lubricity. The new HPWBM is extremely flexible in mud formulations, uses a variety of aqueous base fluids and has temperature stability to 275℉. The system has been applied with a high rate of success in a variety of field applications. The system can easily be prepared and exhibits outstanding drilling performance. The overall performance and easy of handing are significant attributes that significantly brings this system close to performance of OBM. The advent in research and development of novel amine chemistry represented the significant improvement in shale inhibition and development of HPWBM. Key new components of this HPWBM are the unique primary di- and poly-amines. The HPWBM uses an environmentally acceptable, water-soluble clay hydration suppressant (CHS) to stabilize highly reactive clays. The CHS functions in mechanism similar to potassium chloiride in suppressing clay hydration, without being constrained by the performance and environmental issues associated with KCl. The CHS effectively inhibits reactive clays and gumbo from hydrating and becoming plastic, which provides a secondary benefit of reducing the tendency toward bit balling. The data presented in the following table demonstrate how the CHS effectively reduces the hydration and dispersion of reconstituted shale wafers in laboratory tests. CLAY HYDRATION SUPPRESSION Fluid % Hardness change % Hydration

Base fluid 23.40 14.29

+CHS 13.83 11.22 188

% Swelling

31.49

23.50

The reaction of low-molecular weight polyamines with clay can involve several mechanisms including hydrogen bonding, dipole interaction, and ion exchange. Carefully tailored polyetherdiamines

fit

perfectly

between

clay

platelets and binding the plates together. This prevents water absorption from the surrounding aqueous liquid and prevents the shale from swelling. Moreover, the unique molecular structure and blend of polyamines absorbs on the shale surface, thus entering inside the clay platelets and providing excellent shale inhibition (Figure 10-11).

Fig.

10-11

M olecular

model

of

hydration

suppressant binding mechanism to shale layers

10.7.4 Components of HPWBM The newly developed high performance water-based mud (HPWBM) comprises a unique polymeric amine shale intercalator for shale inhibition, an amphoteric polymeric shale encapsulator, a high performance lubricant/antiaccretion agent and a specialized fluid-loss additive. The newly developed HPWBM performed like an oil-based mud in laboratory testing as well as in offset wells using invert emulsion drilling fluids due to highy complicated and reactive shale formations. Along with these novel shale inhibitors, four other specifically designed components are incorporated in new developed HPWBM formulation. The brief description of these four components follows: Dispersant Suppressant. This is a low-molecular-weight partially quaternized water-soluble copolymer. The optimized cationic charges and molecular weight of the copolymer allow it to be adsorbed on negatively charged clay surface keeping the clay plates together without imparting excessive viscosity to HPWBM. Unlike other disperse suppressants this copolymer provides superior shale inhibition without restricting the mud formulations. Antiaccretion Agent. This is a unique blend of surfactants and lubricants which is incorporated in the HPWBM to reduce the accretion of hydrated shale cuttings on the drill bit and prevent the agglomeration of drilled cuttings. The components of this antiacreation agent are compatible with other drilling fluid additives of HPWBM. Fluid loss control agent. This is a low-viscosity modified cellulose polymer. The low viscosity of the polymer allow its functional characteristic and utility in high solids (active and inert) containing drilling fluids, such as highly solids contaminated or high density water-based muds. The polymer provides fluid loss control without affecting the other functional properties of drilling fluid. Rheology modifier. This is a blend of natural polymers to impart high low-shear viscosity for efficient carrying capacity in HPWBM. The synergistic performance of this polymer blend with blend inhibitor extends the utility of rheology modifier in excess of 300℉. 10.7.4 HPWBM Functionality In the conceptional phase of the HPWBM, the drilling performance attributes of invert emulsion 189

systems were examined, essentially identifying the technical features which make OBM the fluid of choice in the most challenging wells. These were key areas in which conventional WBM’s were generally considered inferior or deficient and were used as design criteria for the HPWBM with the aim of emulating the drilling performance of invert emulsion systems. The key attributes were identified as: A. shale stability through reduced or reversed pressure transmission effects B. suppression of reactive swelling clays C. improved cuttings encapsulation and solid removal efficiency D. minimizing differential sticking tendencies E. maximizing rate of penetration(ROP) F. minimizing torque and drag G. environmental compliance These performance attributes are inherent to non-aqueous fluids, but can also be emulated in the new high performance water-based mud (HPWBM) that balances high performance drilling and environmental compliance. 10.7.5 Future Amine Development for Water-Based Mud Drilling fluids applying cationic and anionic nitrogen centered groups have developed steadily for more than 35 years. The earliest applied ammonium salts did not provide acceptable pH or temperature stability for a majority of drilling fluid applications. High-molecular weight anionic and cationic polymers served as encapsulators of cuttings but not particularly well as clay inhibitors. It was only in the last decade that low-molecular weight polyamine chemistry and direct measurement of osmotic pressure in water-based mud have come together to permit development of inhibitive fluids which also provide a predictable and measurable osmotic contribution to overall shale stability. Development is continuing which addresses issues pertinent to amine-based mud chemistry. Developmental goals for the coming years include: A. Extension of amine and oligomer performance to higher temperatures B. C. D.

Economically tailor oligomer to optimum and consistent molecular weight and configuration for improved filtration control and membrane development. Source less expensive amines which meet performance expectations. Investigate of a broad range of organic and inorganic osmotic drivers which complement membrane development.

References 1.

A Subcommittee of the API Southern District Study Committee on Drilling Fluids. Principles of Drilling Fluid Control. Published by PETROLEUM EXT ENSION SERVICE, the University of Texas at Austin. Austin, Texas. In cooperation with INTERNATION

2.

ASSOCIATION OF DRILLING CONTRACTORS, Houston, Texas. 1981. Baker Hughes INTEQ/PUBLICATION/FLUIDS/BROCHURES/AQUA-DRILL

PLUS

SM

3.

SYSTEM/ AQUA-DRILL Glycol Technology Systems. Boyd D. Schaneman, ChevronTexaco, Tom Jones, and Anthony B. Rea, M-I L.L.C. Aphrons Technology – A Solution . AADE-03-NTCE-41.

4.

Burba J.L., Holman W.E., Crabb C.R. Laboratory and Field Fluid Additive Evaluations of 190

Novel Inorganic Drilling. IADC/SPE 17198. 5. 6.

Bourgoyne. A.T., Millheim K.K., Chenevert M.E. and Young F.S. Applied Drilling Engineering. SPE Textbook Series, Vol.2, 1991. CABOT. High-performance Formate Brines for Drilling and Completion. www.cabot-corp.com/csf

7.

ECODRIL. Silicate Drilling Fluid Technologies.

8.

Gray G.R., Darley H.C.H., and Rogers W.F. Co mposition and Properties of Oil Well Drilling Flu ids. Gulf Publishing Co mpany. Fourth Edit ion. 1980.

9.

Green H., Industrial Rheology and Rheological Structure. John Wiley & Sons, New York, 1949, PP.13-43.

10. IDF TECHNICA L MANUA L, THE A DVA NCED TECHNOLOGY OF INTERNATIONA L DRILLING FLUIDDS.

11. Kahn, A. ―Studies in the Size and Shape of Clay Particles in Aqueous Suspension,‖ Clays, Clay Minerals, vol. 6(1957).pp.220-235. 12. Magcobar. DRILLING FLUIDS HANDBOOK. 13. Mc Donald M., Barr K., Dubberley. S.R. Use of Silictate-Based Drilling Fluids to Mitigate Metal Corrosion. SPE 100599. 14. MI. The APHRON ICS Invasion-control system. Micro bubbles.Macro results. nd 15. Norton J. Laperyrouse. Formulas and Calculating for Drilling, Production and Workover. 2 Edition. Gulf Professional Publishing. 2002. 16. Outmans, H.D., ―Mechanics of Static and Dynamic Filtration in the Borehole,‖ Soc. Petro. Eng. J., vol. 3(Sept., 1963). Pp> 236-244; Trans AIME, vol. 228. 17. Schlemmer R., Patel A., Friedheim J., Young S., and Bloys B., Progression of Water-Based Fluids Based on Amine Chemistry–Can the Road Lead to True Oil Mud Replacements. AADE-03-NTCE-36 18. Schlumberger, PowerPlan Technical Manual. 19. Whittaker, Alun: Theory and Application of Drilling Flu id Hydraulics, Boston, MA, IHRDC Publishers (1985).

20. 中油长城钻井有限责任公司钻井液分公司. 钻井液技术手册(Drilling Fluid Technical Handbook).石油工业出版社. 北京. 2005。 21. 鄢捷年主编. 钻井液工艺学. 中国石油大学出版社. 山东. 2006。

191

附表 1 钻井液专业常用公英制单位换算表 类

性能

别

英制单位

井深 井径

公制单位

换算系数

换算实例

m

0.3048

10000 ft = 3048 m

mm

25.4

121/4in = 311 mm

mm

25.4

41/2 in= 114 mm

ft in

钻杆直径

in

钻头尺寸

in

mm

25.4

121/4in = 311 mm

钻压

Lb

N

4.4

20000 lb = 88000 N

转速

r/min

r/min

1.0

钻头水眼尺寸

l/32in

mm

0.7938

10/32 in =7.9 mm

通过水眼流速

ft/s

m/s

0.3048

400 ft/s = 122 m/s

钻速

ft/h

m/h

0.3048

30 ft/h = 9 m/h

体积

bbl

m3

0.159

3000 bbl = 477 m3

泵缸套尺寸

in

mm

25.4

61/2in=165 mm

泵拉杆直径

in

mm

25.4

21/2in = 63.6 mm

泵冲程

In

mm

25.4

16 in = 406 mm

m /min

0.159

8.5 bbl/min= 1.35 m3/min

bbl/min

L/s

2.65

gal/min

3

m /min

3.785×10

gal/min

L/s

6.308×10-2

357 gal/min =22.52 L/s

psi

kPa

6.9

2500 psi = 17300 kPa

ft/min

m/min

0.3048

泵 排 量 机 泵压

械 物

环空返速、钻屑滑落

理

速度

3

bbl/min

ft/min

m/s

5.08×10

性 温度

能

漏斗粘度

0

8.5 bbl/min = 22.53 L/s -3

200 ft/min = 61 m/min -3

C0 = 5/9

F

C0

s/quart

s/quart

357 gal/min = 1.35 m3/min

(0F- 32)

200 ft/min = 1.016 m/s 800F = 27 C0

1.0

lb/gal

3

g/cm

0.12

10 lb/gal = 1.20 g/cm3

lb/ft 3

g/cm3

0.016

74.81 lb/ft 3 = 1.20 g/cm3

psi/ft

kPa/m

22.6

0.52 psi/ft = 11.8 kPa/m

kPa

6.9

4000 psi = 27600 kPa

Pa

0.48

20 lb/100 ft 2 = 960 Pa

dynes/cm2

Pa

0.1

10 dynes/cm2 = 1.0 Pa

剪切速率

s-1

s-1

1.0

表观、塑性粘度

cP

钻井液密度 地层压力梯度 水力压头 剪切应力

屈服值

（动切力） 静切力

旋转粘度计读值

psi lb/100 ft

2

mP a.s

1.0

15cP= 15 mP a.s

2

Pa

0.48

15 lb/100 ft 2 = 7.2 Pa

lb/100 ft 2

Pa

0.48

31b/100 ft 2 = 1.44 Pa

lb/100 ft

dialreading

0.48

10 dialreading=5.1 Pa

Dynes.s /cm

mP a.s

n

100

10Dynes.sn/cm2=103mPa.sn

lb.s n /100 ft 2

mP a.s n

479

1.21lb.sn/100ft 2=575mPa.n

API 滤失量

cm3/30min

cm3/30min

1.0

泥饼厚度

1/32 in

mm

0.8

n

稠度系数 K

Pa 2

3/32 in =2.4 mm

192

油水固相含量 颗粒尺寸

%（V）

%（V）

1.0

µm

1.0

grains /gal

mg/L

17.1

500grains/gal=8550mg/L

ppm

mg/L

µm *

化 学 性 能

离子浓度

S.G

100ppm×1.07=107070mg/L

cm

3

cm

1.0

cm3

Pf、M f、P 1、P2

cm3

cm3

1.0

cm3

亚甲基蓝容量

cm3/ cm3 * *

cm3/ cm3 * *

1.0

cm3/ cm3 *

Lb/bbl

Kg/cm3

2.85

10 Lb/bbl=28.5 Kg/cm3

lb/ft 2/a

Kg/m2/a

4.9

87 lb/ft 2/a=426 Kg/m2/a

mm/a

0.0254

200 mils/a =5.08 mm/a

碱度

处理剂加量 腐蚀速度

3

mils/a 其

它

粘土造浆率

bbl/U.S ton

m /ton

0.175

100bbl/U.Ston=17.5m3/ton

水力功率

hp

kW

0.746

600 hp =448 kW

筛目

Openings/in

Openings/cm

1/2.54

100mesh=39.3 Openings/cm

筛孔边长

µm

µm

1.0

3

筛孔总面积

%

m /m

0.01

30=0.3 m2/m2

钻杆重量

Lb/ft

Kg/m

1.49

19.5 Lb/ft =29.1 Kg/m

2

2

Grains *-格令，英制质量单位，1 格令=64.8 毫克 cm3/cm3 * *-表示亚甲基蓝 cm3/钻井液试样的 cm3

193