Rotary Drilling

The On-line Mud Logging Handbook


Alun Whittaker

by Alun Whittaker

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Rotary Drilling

Aegis Group 244 Ohio Street Vallejo, CA 94590-5051 USA This is Page 1 of Chapter 4: Rotary Drilling

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Alun Whittaker

Rotary Drilling A mud engineer will tell you that well cuttings only contaminate his perfect drilling fluid, while a mud logger will say drilling mud – any drilling mud – ruins all well cuttings. A driller will tell you that both – mud and cuttings – get in the way of him makin' hole, and muck up his boots. In this chapter, we'll look at the process of making the hole that to exist before we can do our job. Plus how can we learn useful things from watching (and listening to) the driller, and how in return we can help him do his job. ✔ The rotary drilling rig ✔ Components of the drill string: drill pipe, drill collars, drilling tools, and types of drill bit ✔ Drilling mud chemistry; water-, oil-, and gas-based drilling fluids and processes ✔ Bore-hole fluid circulation: fluid density, viscosity, flow regimes, and carrying capacity ✔ Bore-hole fluid pressures: density and hydrostatic head, mud flow pressure losses, and hydraulics ✔ Well pressure control: drilling fluid balance, under- and overbalance, well heads and control equipment ✔ Cutting sampling from mud, coring on the drill string or wire line.

This is Page 2 of Chapter 4: Rotary Drilling

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Table of Contents Makin' Hole ......................................................................................................................................................................................................9 The Drilling Rig................................................................................................................................................................................................9 Hoisting Components....................................................................................................................................................................................9 The Deadline Anchor..............................................................................................................................................................................11 Blocks.....................................................................................................................................................................................................11 Draw Works............................................................................................................................................................................................11 Rotating Components..................................................................................................................................................................................11 Rotary Table...........................................................................................................................................................................................11 Top Drive................................................................................................................................................................................................12 Down-hole Motor....................................................................................................................................................................................12 Circulating Components..............................................................................................................................................................................12 The Drill String...............................................................................................................................................................................................16 Drill Pipe.....................................................................................................................................................................................................16 Drill Collars..................................................................................................................................................................................................18 Stabilizers...................................................................................................................................................................................................18 Drill Bit............................................................................................................................................................................................................20 Open Hole......................................................................................................................................................................................................28 Cased Hole.....................................................................................................................................................................................................28 Conductor Pipe...........................................................................................................................................................................................29 Blowout Preventer Stack and Wellhead......................................................................................................................................................29 Surface Casing...........................................................................................................................................................................................30 Intermediate Casing....................................................................................................................................................................................31 Liner............................................................................................................................................................................................................31 Production Casing.......................................................................................................................................................................................32 The Casing String.......................................................................................................................................................................................32 Running Tools.........................................................................................................................................................................................32 Casing....................................................................................................................................................................................................32


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Casing Collars........................................................................................................................................................................................33 Guide Shoe............................................................................................................................................................................................33 Centralizers and Scratchers...................................................................................................................................................................33 Float Collar.............................................................................................................................................................................................34 Cement Plugs.........................................................................................................................................................................................36 Oil Well Cement..........................................................................................................................................................................................37 Bore-hole Volume & Displacement..............................................................................................................................................................38 Drilling Fluids.................................................................................................................................................................................................44 Water-based Mud........................................................................................................................................................................................47 Water......................................................................................................................................................................................................47 Clay........................................................................................................................................................................................................47 Stimulant Additives.................................................................................................................................................................................48 Supportive or Reinforcing Additives........................................................................................................................................................48 Simple Mud Field Testing............................................................................................................................................................................49 Drilling Fluid Density or Mud Weight.......................................................................................................................................................50 Funnel Viscosity.....................................................................................................................................................................................51 Plastic Viscosity & Yield Point.................................................................................................................................................................52 Sand Content.........................................................................................................................................................................................53 Oil and Solid Content..............................................................................................................................................................................54 Filtrate Tests...........................................................................................................................................................................................54 Oil-based Muds...........................................................................................................................................................................................55 Gas-based Dusting.....................................................................................................................................................................................56 Mist and Foams......................................................................................................................................................................................58 Coring.............................................................................................................................................................................................................58 Bottom-hole Coring.....................................................................................................................................................................................59 Specialty Core Barrels............................................................................................................................................................................62 Wire-line Coring..........................................................................................................................................................................................66 Core Logging.................................................................................................................................................................................................70 And Next.........................................................................................................................................................................................................71 ... In this Edition..........................................................................................................................................................................................71 ... On the List...............................................................................................................................................................................................71 Stuck Pipe.........................................................................................................................................................................................71


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Fishing...............................................................................................................................................................................................72 Directional Control.............................................................................................................................................................................73


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Didn't find what you needed here? Sorry. Why not go back to the Chapter

Summaries, and fine a better place to start, or use the Index to search for the subject you need.

List of Figures & Tables Figure 1: A modern rotary drilling rig and the well-bore beneath it. Drilled formation cuttings, oil, water and gas samples are recovered to surface with the circulating drilling fluid. ..........................................................................................................................................................10 Figure 2: The circulating system for a liquid-based drilling fluid - drilling mud. The solids control equipment provides the best locations for cuttings, fluid sampling equipment and sensors. ............................................................................................................................................13 Figure 3: A modern double-decked shale shaker. Cuttings are removed as the drilling mud passes through the upper vibrating coarse screen. Finer, unconsolidated material, and contaminants are removed by the lower fine screen (Illustration courtesy of Baroid, Inc.). ........14 Figure 4: The de-sander and de-silter are larger and smaller hydroclones. In this de-sander, drilling fluids travels upward in a helical path, as fine mud solids are thrown out into the drain water. The de-silter uses smaller hydroclones and mud rapid mud flow, to remove even finer solids (Illustration courtesy of Baroid, Inc.). ....................................................................................................................................................15 Figure 5: The most important components of the drill string are the joints of drill pipe and drill collars. ..........................................................17 Figure 6: The bottom hole assembly provides directional control to the drill bit, and is made up of drill collars, stabilizers and reamers.........18 Figure 7: Are short sections of pipe in the drill string. They perform various specialized functions in controlling drilling. Some examples are shown here. ....................................................................................................................................................................................................19 Figure 8: Drill rate depends on the bit type, size, weight applied by the drill collars, the rotating speed and mud hydraulics. If these are known then other changes in rate of penetration may be interpreted as changes in rock strength, porosity, induration, or fracturing. .......................21 Figure 9: Howard Hughes tri-cone bit design introduced the concept of three self-cleaning, inter-meshing cones..........................................22 Figure 10: The tri-cone rock was developed in the 1930’s. Enhancements Included jet nozzles, sealed bearings, tooth hard-facing and sintered tungsten carbide inserts ....................................................................................................................................................................23 Figure 11: Drill string torque measured at surface reflects the resistance to rotation of the drill bit. Formation strength and consistency may be deduced from the magnitude and variability of torque. ..............................................................................................................................24


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Figure 12: Diamond drill bits have the advantages of an extremely hard cutting structure and the absence of moving parts to wear out. They are also very expensive, tend to drill slowly and the crushed and burned diamond bit cuttings are difficult to identify and describe (Illustration courtesy Eastman-Christensen).......................................................................................................................................................................25 Figure 13: The earliest rotary drill bit design was the drag bit which sheared and scraped soft rocks and sediments much like the action of a wood chisel on a lathe.....................................................................................................................................................................................26 Figure 14: The earliest drag or fishtail drill bit designs were later revived with the innovation of poly-crystalline diamond compact (PDC or “Stratapax”) drilling blanks in place of steel cutting blades. PDC bits offer long bit life coupled with high rates of penetration (Illustration courtesy Diamant-Boart Stratabit)....................................................................................................................................................................27 Figure 15: The guide shoe provides a smooth nose to assist the casing string in reaching the bottom of the hole..........................................33 Figure 16: Components added to the casing string to ensure complete and well-bonded cementation...........................................................34 Figure 17: The float collar separates the cement and drilling fluid and prevents flow into and out off the casing string...................................35 Figure 18: The Cement Plugs separate the cement slurry from the drilling fluid and signal important events in the cementing of the casing string................................................................................................................................................................................................................36 Figure 19: A graphical example of a bore-hole profile. ....................................................................................................................................39 Figure 20: A Table of capacities and displacements of some common sizes of drill pipe, drill collars, and casing...........................................43 Figure 21: Hydrostatic pressure of the drilling fluid has an important effect on the efficiency and consistency with which cuttings are removed from beneath the drill bit cutting structure. ......................................................................................................................................................44 Figure 22: Flow rate and flow regime of the drilling fluid effect the efficiency and consistency with which cuttings are recovered to surface. 46 Figure 23: Mud Balance (Illustration courtesy Magcobar Div., Dresser Industries)..........................................................................................50 Figure 24: Marsh Viscosity Funnel (Illustration courtesy Magcobar Div., Dresser Industries).................................................................................................................................51 Figure 25: Fann V-G Meter (Illustration courtesy Magcobar Div., Dresser Industries)....................................................................................52 Figure 26: The circulation system required for a gas-based drilling fluid system: gas (usually compressed air), mist or foam. .......................57 Figure 27: The Core Bit or Core Head is Similar in Design to a Diamond or P,D.C. Drill Except for the Central Opening for Entry of the Core into the Core Barrel (after Christensen Diamond Products, used with permission) .........................................................................................59


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Figure 28:The Conventional and wire-line recoverable core barrels are similar in design and function. .........................................................60 Figure 29: Inner-sleeved core barrels can be used to improve core recovery from fractured, unconsolidated, or very brittle rocks likely to broken, jammed or lost from the core barrel....................................................................................................................................................62 Figure 30: In the oriented core barrel, a steel blade scribes a groove on the core as it enters the barrel. Later, the scribe line on the core can be aligned with drilling depth and bore-hole directional measurements...........................................................................................................64 Figure 31: The foam-lined and pressurized core barrels offer a way to capture or retain formation fluids from the cored formation when it is returned to surface. ........................................................................................................................................................................................65 Figure 32: The Chronological Sample Taker (CST) or wire-line sidewall coring tool. ......................................................................................67 Figure 33: The Hard Rock Coring Tool (HRCT) or rotary sidewall corer .........................................................................................................68 Figure 34: The TriCore core slicing tool...........................................................................................................................................................69


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Rotary Drilling Makin' Hole The common thread binding all of the many different aspects of mud logging is that they are all real-time logging services: they all take place at the well site while, or very shortly after, drilling takes place. In order to understand and interpret the data obtained from mud logging it is necessary to understand the drilling rig and the tools used to drill the well. This is far less so than for the interpretation of wire-line logs or well tests: these are accomplished after drilling is completed, over a relatively short time interval with stabilized bore hole and formation conditions.

The Drilling Rig The most obvious structure on any drilling rig, offshore or onshore, is the mast or derrick. Even the most rank beginner can recognize this. But what about all the other things hanging on, inside or around the rig (see Figure 1). How many of those do you understand — and understand in what way (if any) they are important in preparing and using a mud log? So, there now follows a very brief primer of drilling rig components. If you need more details, there are other books (Whittaker (Ed), 1985) that provide them.

First time at the well site? Then one of the first things you will learn is that the tall tower that dominates every view of the rig is rarely referred to as the tower. Usually, it is called the d errick or the m ast. ast. Then, you will learn that the 8 or 12-hour work shift on the rig is commonly referred to as a to ur, ur, but that word is pronounced like tower. tower. So if you're told to be there for (what sounds like) the gr aveyard tower, tower, plan on arriving at midnight for the late night--early morning work shift.

The drilling derrick stands on the rig floor or drill floor. This is essentially a large table supporting the tower, hoisting and rotating components. The height of the drill floor above the ground (or deck of an offshore platform or drill ship) allows access to the casing head, blowout preventers and other circulation components. This area, below the rig floor is called the cellar (on an onshore rig) or the moon-pool (offshore).This can all be seen in Figure 1.

Hoisting Components The most important function of the drilling derrick is provide support for the hoisting system used to move the drill string in and out of the bore hole. This consists of several important components sketched in Figure 1.


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Figure 1: A modern rotary drilling rig and the well-bore beneath it. Drilled formation cuttings, oil, water and gas samples are recovered to surface with the circulating drilling fluid.


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The Deadline Anchor This is clamp holding the fixed end of the drilling line. Periodically, this is un-clamped so that fresh drilling line can be spooled from a storage drum into the hoisting system to replace old line that has reached it’s acceptable limit of tonne-miles.: The section of drilling line from this anchor to the top of the drilling mast is called the deadline. It is on this section that strain gauge sensors are placed to measure weight hanging from the hoisting system. Measurement of strain in the deadline can be calibrated in thousands of kilograms (or pounds) of hook-load hanging from the drilling hook. When the drill bit is resting on bottom, then the reduction of hanging weight indicates the weight on bit (WOB) being applied to push the drill bit ahead.

Blocks From the deadline anchor, the drilling line passes several times (usually 8 or 10 times) between the crown block, fixed at the top or crown of the mast), and the traveling block hanging below it. Below the traveling block is the drilling hook used to suspend the drill string, casing, and anything else that needs to be lowered into the well bore.

Draw Works After the last turn over the crown block, the drilling line runs down to the draw works, a large powered drum on the opposite side of the tower from the deadline anchor. This section of the drilling line is called the fast line. The driller’s station is usually beside the draw works. Here, he has a large weight indicator displaying the hook-load and weight on bit (along with other measurements) and a long brake handle that he uses to control the lifting and lowering of the traveling block. He may also have other instruments displaying the total depth and rate of penetration computed from movement of the traveling block.

Rotating Components Modern exploration drilling is accomplished by rotary drilling. The hollow steel drill string consisting of drill pipe, collars, bit and other drilling tools, is rotated to achieve penetration by the drill bit on bottom. There are three most methods of achieving this:

Rotary Table The top section of the drill string is a hexagonal (or square) section pipe called the kelly. Within the rig floor, rollers in a rotary table grasp the flat sides of the kelly which in turn rotates the entire drill string to drive the drill bit.


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Important measurements made here are rotary speed (RPM) and rotary torque, the resistance to rotation of the drill bit on bottom. These measurements are important to the driller in maintaining the best rate of penetration and in detecting signs of drill bit wear or of the drill string getting stuck in the well bore.

Top Drive On many modern rigs, the rotary table has been dispensed with. Instead, a top drive or power sub is suspended from the drilling hook and rotates the top end of the kelly or of the drill string directly. Rotary speed and drilling torque measurements are taken and used in a similar way.

Down-hole Motor When solid-bodied drill bits are used (commonly diamond and PDC bits — see below) the best rates of penetration can be obtained by supplying the highest possible rates of penetration. These can be obtained using a down-hole motor. Getting very high rotary speeds with a rotary table or top drive, requires supplying great amounts of energy, much of which is dissipated overcoming frictional effects of the rotating drill string in the well bore. This friction may also lead to excessive wear and risk of damage to the drill string or well casing (steel pipe used to line upper sections of the well bore). When such bit types are used, they often accompanied by a hydraulically powered turbine or Moinneau-type positive displacement motor installed in the drill string, just above the bit, and powered by the circulating drilling fluid. In such circumstances, the drill string may still be rotated slowly to help prevent sticking problems of stationary drill pipe.

Circulating Components At the top of the drill string, the kelly or top drive incorporate a rotating, high pressure swivel allowing the drill string to be rotated while drilling fluid is pumped into the drill string. The drilling fluid passes from the kelly swivel, through the rotating kelly, drill pipe, drill collars and eventually to the drill bit (see Figure 2). The circulating drilling fluid, which may be a liquid, gas or any combination of these, serves to cool and lubricate the rotating drill string, to clean the drill bit and carry rock cuttings back to surface. It also provides a hydrostatic head to balance formation fluid pressures and prevent a well blowout. In some ultra- deep or non-vertical wells, and when using diamond or PDC drill bits, the fluid may also power the drilling process by rotating a turbine or Moinneau-type drilling motor located in the drill string near the bit.


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Figure 2: The circulating system for a liquid-based drilling fluid - drilling mud. The solids control equipment provides the best locations for cuttings, fluid sampling equipment and sensors.


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The drilling fluid returns to surface through the annulus: the space between the outer bore hole wall and the inner rotating drill string. Through the lowermost recently drilled portion of the annulus, the drilling fluid and its load of drill cuttings is exposed to previously drilled formations and fluids. Shallower formations are protected by casing: large diameter steel pipe which is run and cemented into the bore hole. Attached to the top of the casing is the blowout preventer stack. This is an assembly of several types of valves and seals that can close off the annulus or the entire well bore if control of subsurface pressures is lost. Above the blowout preventers, the mud passes through a conductor pipe and flow line to the solids control equipment. This is where, according to the driller and mud engineer, the contaminants are removed from the drilling fluid. More correctly, as any geologist or mud logger will confirm, it provides their first opportunity to extract precious formation and fluid samples from the contaminating drilling mud. It is, of course, just a matter of priorities.

Figure 3: A modern double-decked shale shaker. Cuttings are removed as the drilling mud passes through the upper vibrating coarse screen. Finer, unconsolidated material, and contaminants are removed by the lower fine screen (Illustration courtesy of Baroid, Inc.).


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The shale shaker is a vibrating mesh screen that removes the drill cuttings and other debris (see Figure 3). The drilling fluid drains from the flow line into a narrow tall tank at the rear of the shale shaker and overflows from there onto the screen. This tank which is called the Regrettably, I am neither a veterinarian, nor a Texan, and so I am possum belly or, in Texas, the sow belly. unable to add any elucidation regarding either the origin, or the This is an ideal location for installing fluid samplers and other drilling mud sensors.

aptness of these names.

Figure 4: The de-sander and de-silter are larger and smaller hydroclones. In this de-sander, drilling fluids travels upward in a helical path, as fine mud solids are thrown out into the drain water. The de-silter uses smaller hydroclones and mud rapid mud flow, to remove even finer solids (Illustration courtesy of Baroid, Inc.).


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Passing through the vibrating shale shaker screen, the mud falls into a settling pit where finer material can settle out before the mud goes back to the mud pit to be mixed and conditioned in order to be returned to the bore hole. The well cuttings fall from the shale shaker screen into a drainage sump which is titled the reserve pit (on a modern rig, the term is a euphemism only, it is in fact a sealed waste pit, periodically sucked out into a honey wagon and hauled away). Cuttings sample catching equipment can be located at this point. If the rig crew feel particularly favorably inclined toward mud loggers, there may also be a stairway and safety rail here. The de-sander and de-silter do not operate continuously but are turned on by the Mud Engineer when he wishes to remove recirculating fine debris from the drilling mud that would otherwise cause abrasion of drilling equipment. Both devices are variants of the hydroclone. Drilling fluid flows in a helical path upward through the conical elements while water passes downwards (see Figure 4). Mud viscosity prevents mixing of the fluid flows while dense solid particles are thrown out of the mud and carried away by the water. As the name suggests, the desilter, with smaller cones, promotes more rapid flow and therefore throws out finer solids material. The fine grained material produced from the de-sander, de-silter ,and the lower screen of a double deck shale shaker do not usually represent fresh, whole cuttings but may be unconsolidated grains and abraded fragments that have been re-cycled through the bore hole several times. However, the devices must be sampled regularly, whenever they are running. This allows recognition of the typical material and can assist in locating and identifying newly encountered unconsolidated clastic sediments. significant detrital minerals or micro-fossils. For example: you have encountered a drilling break and asked the driller to pick up and circulate bottoms up. When the bottom hole sample is due to arrive you see nothing coming over the top screen of the shale shaker, but you do find a quantity of fine sand on the lower deck and the derrick man reports an increase in the volume of fine material being thrown out of the de-sander: ✔ Have the well penetrated an unconsolidated sandstone reservoir? ✔ Does the fine sediment now arriving in the mud look different in appearance from that seen previously? ✔ You have been looking, haven’t you?

The Drill String The drill string (see Figure 5, Figure 6, and Figure 7) provides communication between the surface (lifting, rotating, and circulating) power systems and the drill bit. It consists of:

Drill Pipe The uppermost, and longest, section of the drill string is made up of ten to fifteen meter long sections of strong, flexible steel pipe with strengthened, threaded enlarged tool joints at the ends. Drill pipe serves as the connection for lifting, lowering and rotating the bottom hole assembly. It also serves as a conduit for the circulation of drilling fluid.


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Figure 5: The most important components of the drill string are the joints of drill pipe and drill collars.


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Drill Collars Most of the lower section of the drill string, the bottom hole assembly (BHA), consists of thicker, six to seven meter long sections of more rigid, thicker walled pipe. In addition to the functions of the drill pipe, the drill collars also provide weight to force the drill bit ahead, and stiffness to maintain the well on a straight path.

Stabilizers Stabilizers are short, drill collar-like sections of pipe which make up the remainder of the bottom hole assembly. External blades or rollers give an overall diameter similar to that of the drill bit. Stabilizers (or reamers) assist the drill collars in maintaining directional control. Also, when drilling unconsolidated formations, the full-gage stabilizers provide a hole cleaning, reaming function, that helps keep the bore hole open to its full size and prevent the drill string from becoming stuck in the hole.

Figure 6: The bottom hole assembly provides directional control to the drill bit, and is made up of drill collars, stabilizers and reamers.


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In addition to these major components there are numerous other short sections of pipe called subs. Each type of sub has its own special application in drilling (see Figure 7), for example:

Figure 7: Are short sections of pipe in the drill string. They perform various specialized functions in controlling drilling. Some examples are shown here.


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✔ Bit and crossover subs are used to connect together components with different types and sizes of threaded pins and boxes. The bit sub may also contain a check (or one-way) valve allowing drilling fluid to be pumped down to through the bit to bottom, but to prevent any flow back up the inside of the drill string that may be caused by hydrostatic imbalance. ✔ Shock and bumper subs are gas-filled shock absorbers used to maintain constant weight on bit when drilling from a moving drill ship or floating drilling platform. ✔ A junk sub has small catcher pockets. The sub is run immediately above a bit to catch lost bit cones or other heavy metal debris, thrown up by turbulence that, if left in place, may cause damage to later drill bits

When a junk sub is run, the mud logger should always be on hand when it is tripped out of the hole. Although intended to recovered metal fragments, it does sometimes capture fist- sized fragments of drilled formation, giving a fresh appearing sample that should not be missed.

have little impact on mud logging, however, and so we will skip any detailed discussion of them here.

Drill Bit The lowermost item in the drill drill string, the drill bit is of critical interest to the mud logger. The rate at which the bit penetrates through the formation is controlled by mechanical operating parameters and by the physical strength of the formation. Instantaneous changes in the drill rate can indicate to the skilled geologist formation changes caused by variations in porosity, mineralogy and cementation even before cuttings are seen (see Figure 8). Conversely, by understanding these relationships, the geologist can assist the drilling engineer in selecting the most suitable bit and operating parameters in order to maximize rate of penetration and bit life. The drill bit is also the geologist’s sampling tool. Drill bits vary greatly in design, cutting action and therefore in the size, shape and nature of the drill cuttings that they produce. The most common type of drill bit used in commercial drilling features the tri-cone rock bit design first used in the 1930’s. Rotary cutter drill bits, developed by Howard Hughes (senior) and others, used two, three or even four cylindrical rollers, but the modern tri-cone design was patented by the younger Howard Hughes (yes, him!) in 1934. This design (see Figure 9) uses three rotating cones with inter-meshing teeth. The rotating cones crush and gouge material from the bottom of the hole, and the inter-meshing of the teeth makes them selfcleaning. In effect, each row of teeth on a cone crushes solid rock beneath the bit, and then rotates off-bottom to pick clean the crushed-rock debris in the gaps between the teeth of the adjacent cone.


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Figure 8: Drill rate depends on the bit type, size, weight applied by the drill collars, the rotating speed and mud hydraulics. If these are known then other changes in rate of penetration may be interpreted as changes in rock strength, porosity, induration, or fracturing.


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Figure 9: Howard Hughes tri-cone bit design introduced the concept of three self-cleaning, inter-meshing cones. For best effect in all rock types, the teeth may be (see Figure 10): ✔ Long, slender, and widely spaced for drilling formations with low cohesion, or ✔ Short and broad for drilling harder rocks. For longer life and abrasion resistance, the milled steel teeth may be hard-faced with abrasion-resistant material, or they may be replaced by inserts made of sintered tungsten carbide. The shape and size of the rock cuttings produced by a tri-cone bit reflect the shape, length and spacing of the teeth on the cones. Long slender teeth produce large, freshly broken cuttings from soft rocks and sediments. Broad teeth and inserts produce smaller, more rounded, crushed and ground cuttings from hard rocks. The torque, or resistance to rotation of the drill bit is measured at surface and will, like rate of penetration, assist the geologist in identification of formation boundaries while drilling proceeds (see Figure 11).


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Figure 10: The tri-cone rock was developed in the 1930’s. Enhancements Included jet nozzles, sealed bearings, tooth hard-facing and sintered tungsten carbide inserts Unfortunately, the tri-cone bit has numerous bearing surfaces and seals. As a result, both the cutting ability and cone tightness tend to deteriorate in only a short time and, with them, rate of penetration and cutting quality decline. tri-cone bits must be replaced regularly, every 10 to 50 hours, requiring the entire drill string to be pulled out of the hole with consequent time delay and risk of bore hole damage.


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Figure 11: Drill string torque measured at surface reflects the resistance to rotation of the drill bit. Formation strength and consistency may be deduced from the magnitude and variability of torque.


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Diamond drill bits have been widely used for ultra-deep drilling of hard and abrasive formations. The diamond drill bit (see Figure 12) consists of a solid steel body with central ports for drilling fluid circulation and the remaining lower and side surfaces set with boart grade industrial diamonds. The cutting action of the drill bit depends upon a continuous grinding and scraping as the bit rotates on bottom. The grinding produces fine cuttings and rock flour which, due to frictional heating, often show signs of thermal degradation.

Figure 12: Diamond drill bits have the advantages of an extremely hard cutting structure and the absence of moving parts to wear out. They are also very expensive, tend to drill slowly and the crushed and burned diamond bit cuttings are difficult to identify and describe (Illustration courtesy Eastman-Christensen)


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The advantage of a diamond drill bit is its long life of hundreds of hours, resulting from the hardness of its cutting structure and the mechanical simplicity of its design, lacking moving parts and seals, that would be subject to wear and erosion. Its disadvantages include high cost, slow rates of penetration, unresponsive to changes of formation lithology and, most important to the geologist, poor recovery and quality of drill cuttings samples.

Figure 13: The earliest rotary drill bit design was the drag bit which sheared and scraped soft rocks and sediments much like the action of a wood chisel on a lathe Amongst the earliest rotary drill bit designs were the drag and fishtail bits (Figure 13) which sheared and scraped soft rocks and sediments much like the action of a chisel on wood turning in a lathe. Unfortunately, these bits lacked the hardness and wear resistance for use in consolidated rocks and they were made obsolete by the introduction of roller bits. In recent years, the drag or shearing-action drill bit design has been revived by the introduction of Poly-crystalline Diamond Compact (PDC) drilling blanks. The PDC drill bits (Figure 14) may look like and older fishtail bits, but the steel scraping and cutting blades are studded with large, hard, abrasion resistant, PDC drilling blanks, manufactured from a bonded mass of micro-crystalline synthetic diamonds. For harder formations the PDC bit may have more the appearance of a diamond drill bit but the small diamonds are replaced with larger PDC drill blanks.


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PDC drill bits, sometimes called Stratapax® or TSP® (Thermally Stable Products), produce large, fresh sheared drill cuttings with little surface damage or mechanical deformation. They are also relatively cheap and drill very quickly in soft, medium and moderately hard formations. Unfortunately, they are unsuccessful in drilling the very hardest and most resistant rocks. In these formations or if they used with unsuitable drilling parameters, PDC bits can produce churned and ground cuttings almost as bad as those from a diamond bit.

Figure 14: The earliest drag or fishtail drill bit designs were later revived with the innovation of poly-crystalline diamond compact (PDC or “Stratapax”) drilling blanks in place of steel cutting blades. PDC bits offer long bit life coupled with high rates of penetration (Illustration courtesy Diamant-Boart Stratabit)


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Most recently, several hybrid designs have been proposed involving PDC studded cones and rollers. These may, eventually, become the best solution to efficient drilling of very hard rocks. The geological significance if rate of penetration, and relative performance of different drill bits is discussed again in Chapter 11:The Basic Mud Log. The mathematical treatment of drilling data to help optimize drill bit selection has full treatment in Chapter 12: Geo-pressure Engineering Logs.

Open Hole Open hole is the lowermost section of the the bore hole: the section that has been most recently drilled, and which approximates to the size of the drill bit in diameter. The intent of mud logging is to examine and evaluate rock and fluid, foot-by-foot as is liberated, by the drill bit, at the bottom of the hole. In reality, oil, gas, water, and rock material from the entire open hole section is in constant interaction with the the circulating drilling fluid. This effect has to be considered when evaluating mud log data (see Chapter 11:The Basic Mud Log), and must be considered when designing drilling, drilling fluid programs (see Drilling Fluids, later in this chapter.) Periodically, to protect open hole zones from contaminating each other, or to prevent bore hole collapse (see the discussion of formation pressures and flow in Chapter 12, Geo-pressure Engineering Logs ), it is necessary to set and cement steel casing to line the bore hole.

Cased Hole The uppermost section of the bore hole is lined with steel casing, cemented in place to support it, to prevent pressure and fluid communication between porous zones in the formations behind the casing. The casing provides a bore hole of known diameter for further operations, and to: ✔ Prevent collapse of the bore hole wall, and caving into the returning drilling fluid stream ✔ Provide a means of containing formation pressures, and intra-zone flow, by preventing fracturing of upper, weaker zones ✔ Provide a means for attaching surface, well control equipment: the wellhead, blowout preventers, and production equipment ✔ Confine production of fluids from different zones into the well bore, when testing, or in final production ✔ Permit installation of production stimulation, and artificial lift equipment for producing the well


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The various sections of cased hole can be functionally defined (in approximate top to bottom order) as follows. ✔

Conductor Pipe

✔

Blowout Preventer Stack and Wellhead

✔

Surface Casing

✔

Intermediate Casing

✔

Liner

✔

Production Casing

Conductor Pipe The conductor serves as a conduit to raise the circulating fluid high enough to return the drilling fluid to the pit (see Figure 1). The conductor runs from the wellhead or blow out preventer stack up to the rig floor, terminating in a flared section (known as the bell nipple, and flared so that drill bits and other tools can be run into the well without hanging up on the top of the conductor pipe) just below the rotary table. From the side of the conductor, near to its top, a horizontal mud return line carries the returning drilling fluid to the shale shaker and mud pits. Before initial drilling is completed, surface casing set, and the high pressure blowout preventers installed, a diverter, or low-pressure annular preventer, is usually attached at the top of the conductor, allowing the bore hole to be partially closed off, and the overflowing fluid to be diverted into the return line, or to the reserve pit. On an onshore well, or an offshore (fixed, or jack-up) platform, the conductor is usually a short, simple, section of pipe, only a few meters long, standing above the blowout preventer stack, in the cellar (on an onshore rig), or in the moon-pool (offshore). On a floating rig, or drill ship, the conductor may be much longer, running from the seabed-located wellhead, and blowout preventers, all the way to the surface. Much more than a simple pipe, this type of conductor may contain buoyancy chambers, telescopic joints, electrical, and hydraulic conduits for the remote control systems used to control the wellhead attachment, and operate the blowout preventers on the seabed.

Blowout Preventer Stack and Wellhead The wellhead resides at the very top of the casing, and serves as the support base, or attachment point for blowout preventers (while drilling) and for the production tree (if the well is permanently completed for production). It is a permanent fixture, bolted or welded to the conductor pipe in the cellar (on an onshore rig) or the moon-pool (on offshore, fixed or mobile platforms). On a floating rig, or drill ship, the well head is located on the seabed, attached to the surface casing, and accessed by remote control.


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The wellhead also supports the well control equipment, beneath the rig floor (or on the seabed), that can be closed on the open hole, or around drill string to hold it in place and prevent uncontrolled fluid flow to surface: a well kick, or blowout. Types of blowout preventers include: ✔ Pipe Rams, designed to be hydraulically (or, in emergency, manually) closed around the size (outside diameter) of drill pipe in use. Obviously, such appropriately-sized pipe rams will not be able to close around the larger diameter drill collars, or even the enlarged external upsets of the drill pipe tool joints. ✔ Blind Rams, designed to be hydraulically (or, in emergency, manually) closed, and to entirely seal the entire (inside diameter of the) uppermost string of casing. Blind rams are used to safely seal the bore hole, preventing any influx of fluids, when there is no drill string in place. For example, when round tripping, to replace a worn drill bit. ✔ Shear Rams are a variation of blind rams. As the name suggests, shear rams can be closed even when the drill string is in place, cutting through (or shearing) the drill pipe, so that the bore hole can be completely sealed when a blowout has occurred. ✔ The Annular Preventer contains a flexible, sealing ring that can be hydraulically compressed vertically, so that it bulges inward to close off the bore hole, or any pipe or tool inside it. Under full compression, the annular preventer can close off the open bore hole. At lower compressions, it can close and seal around drill pipe (even the tool joints), drill collars, and even the square or hexagonalshaped kelly (see Rotary Table, above). At slightly less than full compression, the annular pressure can allow the drill string to be carefully moved up and down, or even rotated, with a slight leakage of drilling fluid serving as a lubricant. A gage, immediately below the blowout preventers, indicates the shut-in casing pressure, so that the rams are not opened with an unexpected, possibly uncontrollable pressure below.

Surface Casing This the first permanent string of true casing run into the hole. In subsequent operations, the surface casing will serve as the base for the wellhead and blowout preventers, and as the hanger, and pressure seal for all later strings of casing, The surface casing may be put in place by: ✔ Being driven, using a pile driver, ✔ Washed-down, by circulating water down through the casing and washing away loose sediment below, ✔ Actual drilling, with a large diameter drill bit, and circulating drilling fluid, or ✔ Combinations of these, sufficient to gain the necessary depth of penetration, and solid footing


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At the top of the surface casing, and below the wellhead, the casing hanger assembly is installed, so that subsequent casing strings can be run into the bore hole, through the wellhead and blowout preventers, and then be latched automatically inside the wellhead housing, making a permanent seal. There is no necessity to remove, and re-install the wellhead and blowout preventers on later casing strings. After latching each subsequent casing string into the hanger assembly, it is only only necessary to close the blowout preventers, pressure test to confirm that fluid cannot escape between the new, and older casing strings.

Intermediate Casing Most subsequent strings of casing serve the purpose of protecting shallower and deeper zones from communicating, contaminating, or damaging each other. They are usually referred to as intermediate, or protection casing. Most commonly, protection casing protects against loss of circulation in shallow formations when heavy mud densities are required to control pressures when for drilling deeper zones. On the other hand, intermediate casing may also be set through shallow, abnormally high-pressured zones, so that the drilling fluid density can be reduced in order to safely drill into deeper, normally pressured formations. Commonly, after drilling to a planned depth, the bore hole is conditioned by circulating clean drilling fluid for some time. Then, the necessary open hole wire-line logs (those measurements that cannot be made later, through the steel walls of casing) are run. After this, intermediate casing can be run, cemented, and pressure tested. Next, with the appropriate new drilling fluid composition mixed in the pits, and a smaller drill bit, drilling re-commences.

Liner Liners are mostly used to provide a low-cost completion of a well. Unlike casing which is hung from the wellhead, and runs from the surface to a given depth, a liner is hung from a hanger-like device inside, and near to the bottom of, the previous string of casing. Using a liner, deeper zones in the well may be production tested, in an entirely enclosed, known volume bore hole, without the expense of running an entire new casing string to surface. Depending on the eventual purpose of the well, liners may be installed in different ways. For example: ✔ Liners suspended from a hanger device inside the previous casing string may be cemented in place, or ✔ They may be suspended in the well without cementing, allowing later removal, or replacement, or ✔

A tie-back string may be run all of the way from surface down to the top the liner. In effect, this converts the liner into a regular casing string.


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Production Casing Production casing (or oil string) serves the same function as a liner, but is hung from surface to protect tubing and other equipment used in a producing well.

The Casing String Running Tools Running casing into the hole is little different from tripping a new drill bit and drill string into the hole except, of course, that everything is larger and usually heavier. It is necessary to remove the rotary table from the rig floor, and to replace the usual elevator, and tongs, used to make-up (and break-out) drill pipe connections with much larger replacements. In place of the kelly, separate circulating, or cementing heads are required to: ✔ Periodically fill the casing with drilling fluid, to prevent it collapsing under hydrostatic pressure ✔ Pump the cement slurry down inside the casing, when it is in place, and ✔ Pump drilling fluid down into the casing to displace the cement out into the annular space between the casing and the bore hole wall.

Casing Casing is delivered to the well site as seven to ten meter-long sections of seamless steel pipe, that is usually classified by: ✔ Outside diameter, for example inches, or centimeters ✔ Linear weight, for example pounds per foot, or kilograms per meter

Although the casing specification is of no significance to formation evaluation, it is usual for the casing size and weight be reported on the mud log, at the appropriate depth (depth to the casing guide shoe). This is just part of the mud logs role as a concise record of all activities on the well.

Each section of steel pipe is threaded on each of its outer ends.


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Casing Collars Casing collars are not in any way related to drill collars. They are in fact, simply steel connectors used to assemble the sections of casing into a casing string. Casing collars are short sections of steel pipe, with their inside diameter matching the outside diameter, of the casing. The casing collars are threaded throughout their interior to match the thread on the outer ends of the casing sections.

Guide Shoe This is a casing collar onto which a rounded nose of drillable material (cement, or a soft metal alloy) has been molded. The guide shoe is threaded onto the lowermost section of casing, and aids in guiding the casing string past ledges and obstructions in the bore hole, on its way to bottom. There is a hole through the middle of the guide shoe so that, if it does become stuck in the hole, drilling fluid can be circulated through it to wash away debris.

Figure 15: The guide shoe provides a smooth nose to assist the casing string in reaching the bottom of the hole

Centralizers and Scratchers Centralizers and scratchers are attached around the outside of casing joints all along the casing string – particularly where the casing will eventually be in open hole. Their purpose is to ensure that cement forms evenly around the casing, bonds securely in place, and that there are no gaps, or channels allowing formation fluid to later flow behind the casing.


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As the casing string is run into the hole it is periodically rotated and reciprocated, allowing the centralizers and scratchers to scrape the wall of the bore hole, removing mud filter cake (see Drilling Fluids, later in this chapter). This improves the quality of the bond to formed by the cement and the bore hole wall. When the casing string is finally in place, the centralizers (at the right, in Figure 16) have a second function. They fix the casing string centrally in the bore hole and ensure uniform cement placement all around it.

Figure 16: Components added to the casing string to ensure complete and well-bonded cementation

Float Collar The float collar is an alternative casing collar inserted between two joints of casing, near to the bottom of the bottom of the casing string. It incorporates a one-way valve (made of an easily drillable material) and performs a number of functions while the casing string is being run and cemented: ✔ While the casing is being run into the hole, the float collar works like a blowout preventer, preventing drilling fluid, or formation fluids from entering the casing string, and flowing to surface.


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✔ By keeping out dense drilling fluid, the float collar effectively reduces the weight of the casing string allowing it to float to bottom. This reduces strain on the surface hoisting gear. However, empty casing may also be collapsed by A n ot relevant, but ver y useful tip: the connections of regular casing collars are external hydrostatic pressure, so some drilling fluid doped with a friction-reducing pipe dope similar to that used on drill pipe and (or water) may need to be added from the top of drill collars. This helps make a pressure tight seal, and also allows easy uncasing string using a circulating head. ✔ The float collar serves as a stop for the top and bottom cement plugs used to separate drilling fluid and cement (see below). ✔ After the casing string is in place, and the cement slurry has been displaced out into the annulus, the float valve prevents the denser cement from flowing back into the casing string.

threading if there are problems. And the casing needs to be pulled back. On the other hand, the threads on the guide shoe and float collar are doped with a highly adhesive thread-lock compound, to prevent them from being spun and un-threaded by the turning drill bit, during drill-out. If you can get hold of a little left-over of this thread compound, it makes the very best, most permanent glue you ever used!

Figure 17: The float collar separates the cement and drilling fluid and prevents flow into and out off the casing string

Note that the float collar is normally run a few joints of casing above the bottom of the casing string. If it desired to run it at the bottom, then a combination float shoe (that is flo at co llar + guid e sh o e ) can be used.


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Cement Plugs After the casing string is in place, the cement is introduced into the top of the casing string using a cementing head. Mixing with drilling fluid may degrade the setting ability of the cement, and so they are separated from teach other by the cementing plugs. Two different cementing plugs are used: ✔ Before cementing, the first, or bottom plug is put into the casing string. It has has a hollow core made of wood or some other easily drillable material (usually wood, or pot metal, an aluminum alloy) with an outer layer, at top diaphragm, and fins made of rubber. ✔ The bottom plug is followed by the calculated volume of cement slurry -- enough to fill all of the annular space between the casing string and the open hole (with an appropriate safety factor for hole enlargement and fluid loss). The cement, which is normally heavier than the displaced drilling fluid, pushes the plug downwards, and the fins on the plug wipe the inside of the casing clean of drilling fluid, to prevent it contaminating the cement. ✔ When the calculated volume of cement has been added, the second or top plug is placed into the top of the casing string. This plug is identical to the bottom plug except that it has a solid core of wood or other easily drillable material. ✔ The top plug is followed by pumping the calculated volume of drilling fluid -- enough to drive the cement out into the annular space between the casing string and the open hole, leaving little or no cement remaining inside the casing string.

Figure 18: The Cement Plugs separate the cement slurry from the drilling fluid and signal important events in the cementing of the casing string


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✔ When the bottom plug reaches the float collar, it is stopped (or it bumps), the cement displacement is temporarily halted, and a back-pressure is noted at surface to mark the event. ✔ Because the bottom plug is hollow, only the thin rubber diaphragm preventing further displacement does not long survive the increased pressure. Almost immediately, the diaphragm bursts, cement flows through, and continues to be displaced below the float collar and out into the annulus. ✔ When the top plug reaches the float collar, it also bumps, and cement displacement is once again halted, and a second backpressure is noted at surface to mark this event. ✔ Because the bottom plug is solid, no further displacement is possible and pumping must stop. The calculated volume of cement now remains below the float collar and in the annulus. ✔ Although the cement in the annulus is usually denser than the drilling fluid, it could flow back into the casing string, but the float collar acts as a one-way valve, and prevents it from flowing back. ✔ The casing is lowered slightly, enough to latch it into the casing hanger, and the casing string is pressure sealed. After the cement has set, and the casing string and blowout preventers have been pressure tested, then it is possible to trip a smaller drill bit into the hole, drill out the drillable materials of which the float collar, guide shoe, top and bottom plugs are made, and the small volume of cement retained between the float collar and the guide shoe, and then begin drilling new formation.

Oil Well Cement The cement used in bore-hole applications, is basically Portland cement with some additives, and enhancers, similar to those used in drilling fluids. For example: ✔ Accelerators to promote the setting of cement, and reduce excessive waiting time, particularly in cooler, shallower environments. ✔ Retarders to extend the time over which the cement slurry remains pump-able. At higher down-hole temperatures, the chemical reaction between cement and water is accelerated, and thickening time reduced. ✔ .Lightweight additives to reduce slurry density, or ✔ Heavyweight additives to increase cement slurry density when abnormally high formation pressures are expected ✔ Fluid-loss additives to reduce filtration rates and fluid loss, similar to that of drilling muds ✔ Friction reducing additives or thinners, to reduce the apparent viscosity of the slurry, and frictional pressure losses when pumping.


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Unlike drilling fluid, it is preferred that cement displacement be in turbulent flow to promote more efficient flushing of mud and filter cake from the annulus. ✔ Lost-Circulation Additives to prevent extreme fluid loss. In most circumstances, lost circulation additives are used with the conditioning drilling mud, so that the thief zone can be thoroughly sealed before casing and cementing is attempted. In worse situations, however, it may be necessary to add fibrous, and granular lost circulation materials to the cement itself.

In yet other situations, extreme lost circulation while drilling may be treated by pumping a slug of cement slurry mixed with lost circulation materials into the thief zone. Another trick is to pump a slurry of dry Portland cement mixed with diesel or crude oil. The cement will, of course, not set while it is mixed with oil. However, when the slurry is lost into the thief zone and mixes with formation waters, it will rapidly set, and seal the zone. Lost circulation is discussed in more detail later. later.

✔ Salt-saturated cements were originally developed for cementing through salt diapirs to which fresh-water slurries do not bond well. They are now also used to improve the cementing of claystone and shale sections that are particularly sensitive to the swelling effects of fresh water.

Bore-hole Volume & Displacement To the mud logger, the most important drill string information involves the numbers, lengths, inside and outside diameters of the drill pipe and drill collars used in the assembly. This is called the pipe It takes a little diplomacy, of course. If you start by out by telling the driller he's wrong then, more than tally. The count of pipe joints and likely, you'll end by changing your depth calculation to match his -- only to have to change it back again, the measurement of their lengths when a more trustworthy wire-line log, or drill string re-measurement (aka strapping o ut o f th e h o le ) are made by the driller and his becomes available. Better to ask if you can see his tally book, in order to find out where you may have crew, but the mud logger must keep an independent pipe tally. In gone wrong. practice we find that calculation errors are far more common than measurement errors. Working independently with regular cross-checks, the driller and mud logger can find and correct errors before serious


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problems develop. Most obviously, these figures are necessary in order to calculate the length of the drill string and, therefore, the depth of the well as drilling proceeds. They are also used, with the measured output of the mud pump to calculate the displacement time (in minutes, or number of pump strokes) of the drill string and return annulus. These figures are the very basis of mud logging, allowing measurements and observations made at surface to be lagged back in time and depth, to their point of origin. We will encounter these figures in several applications later in the book. The most important is in estimating the time necessary to circulate drilling fluid from surface, down to the drill bit and back up to various points in the annulus.

Figure 19: A graphical example of a bore-hole profile.


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Figure 19 shows an example bore-hole profile. In everyday calculations it is acceptable to make certain simplifications: ✔ The drill bit, stabilizers and other subs are ignored so that the inside and outside diameters of the drill collars are used for the entire bottom hole assembly, ✔ We ignore internal and external upsets, so that drill pipe is assumed to have uniform inside and outside diameters. Both of these assumptions are acceptable within the limits of error in other input data. For example, the estimated diameter of the un-cased, open bore hole. From the measured output of the mud pumps and the known dimensions of the drill bit, drill pipe and drill dollars, you can compute the drill string displacement, annular volume and the downward and upward circulation times. For each section of the bore hole:

..................... Equation 1

..................... Equation 2

..................... Equation 3


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..................... Equation 4

For the entire well:

..................... Equation 5

..................... Equation 6

..................... Equation 7


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Where: CA

=

Annular capacity, cubic meters

CB

=

Boreholes capacity, cubic meters

CS

=

Drill string capacity, cubic meters

DS

=

Drill string displacement, cubic meters

DnA

=

Bore hole inside diameter, millimeters

DnB

=

Drill string outside diameter, millimeters

DnC

=

Drill string inside diameter, millimeters

Ln

=

Annular section length, meters

QP

=

Mud pump output, cubic meters per second

TC

=

Drilling fluid circulation time, seconds

TD

=

Drilling fluid down time, seconds

TL

=

Drilling fluid up or lag, seconds

Although these calculations are quite simple, most people like to have a little help with this kind of problem. Figure 20 provides the capacities and displacements for several common sizes of pipe.


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Figure 20: A Table of capacities and displacements of some common sizes of drill pipe, drill collars, and casing


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Drilling Fluids Once the drill cutting have been released by drilling, they must be carried from under the face of the drill bit into the outer annulus and then back to surface. This is the job of the drilling fluid. Drilling fluids may be liquid or gas-based. There are differences in the circulation equipment needed for each of these fluid types and, for each, there are definite advantages and disadvantages in drilling operations and sample recovery quality.

Figure 21: Hydrostatic pressure of the drilling fluid has an important effect on the efficiency and consistency with which cuttings are removed from beneath the drill bit cutting structure.


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A column of dense, water or oil-based drilling fluid applies a hydrostatic pressure on the bottom of the hole to overbalance formation pore pressure and prevent uncontrolled fluid influx: a well kick or blowout. Unfortunately, excessively dense fluid applies too great an overbalance and holds the drill cuttings and other broken material in place beneath the drill bit. Several rotations and many tooth impacts are required before the cuttings are small and loose enough to be carried away from below the bit by the fluid jetting from the bit’s jet nozzles. If mud density is excessive, this chip hold-down effect will produce very small, excessively ground cuttings and, by preventing access to fresh, uncut formation, will retard rate of penetration (Figure 21). If the differential pressure is lower or negative (meaning that the formation pressure is greater than bore-hole hydrostatic pressure), then formation fractures caused by the bit will be enlarged and extended by flowing, expanding pore fluid. Large, fresh-surfaced cuttings will be carried quickly away from bottom, exposing fresh formation to the bit for increased rate of penetration. Gas-based drilling fluids offer an extreme occurrence of this. They have extremely low density and so provide almost no hydrostatic pressure at the bottom of the hole. Cuttings are blown explosively from under the drill bit and carried back to surface at very high velocities. The maximizes rate of penetration, but the violent removal of cuttings results in their almost total disintegration. Gas drilled cuttings often consist of fine rock flour of little use to the geologist. Liquid-based fluids travel to surface with their load of cuttings at a much lower pace, allowing efficient, safe recovery of whole cuttings. Cuttings recovery or lag time is controlled by the mud flow rate, annular capacity and well depth. It will also be modified by the mud flow regime, cuttings shape, size and density (Figure 22). In laminar and turbulent flow, there is a velocity distribution in the annulus with mud flowing faster in the center of the annulus and slowest at it’s inner (drill pipe) and outer (bore-hole wall) boundaries. Solid particles tend to slip outward from the high velocity central region to the low velocity margins. Slippage rates vary with particle shape, size and mass resulting in a non- uniform, partial mixing of cuttings with material from the formations above and below. A geological sample log created from the examination of cuttings samples will never show truly sharp formation boundaries. Despite sharp drilling rate changes, drilling breaks, the cuttings are always mixed and honest cuttings descriptions will appear to indicate apparently transitional bed boundaries. This must be considered when combining This is an important reason why the recommended mud log format used in this book includes two drilling measurements, cuttings cutting lithology columns: observations and other mud logging One for accurate presentation of actual cutting components and amounts, data to prepare an interpreted presentation of the formations The other for an interpretation of the actual formations penetrated and their boundaries penetrated.

based on all available real time observations and measurements.


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Figure 22: Flow rate and flow regime of the drilling fluid effect the efficiency and consistency with which cuttings are recovered to surface.


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Water-based Mud The most common drilling fluids are so-called gel muds consisting of mixtures of water and a pure high-yield clay. They have an excellent carrying capacity for drill cuttings at reasonable annular velocities and, when fluid flow is halted, the fluid rapidly forms a stable colloidal gel to prevent the cuttings from settling.

In rig parlance, clay denotes an unconsolidated formation to be drilled through, whereas the pure, graded clay mineral-based mud materials that arrive in sacks or from a hopper are gel.

The clay-water slurry provides adequate density to control most subsurface pressures, and they filter out of the mud into permeable formation, to line the bore-hole wall with a smooth impermeable filter cake. The common components of a water-based mud can be divided into four functional groups:

Water ✔ Fresh, ✔ Brackish water, or ✔ Marine brines (seawater) are used Commonly, whatever water is available at the well site is used.

Clay ✔ Wyoming Bentonite is used for fresh and brackish water systems but it does not yield (swell by absorbing water) easily in more saline water. ✔ Attapulgite or Salt Gel does not have so great a maximum yield but is more responsive in sea water and brine systems. Pre-hydrated, and chemically stabilized, Bentonite may also be used with seawaterbased muds.

Historically, basic mud was prepared by driving a herd of cows through the nearest available muddy pond. This is another reason why the sump used as temporary storage (for later sanitary disposal) of surplus, or contaminated mud and cuttings is still called the reser ve pit. pit. These days the chemistry and rheology of the thixotropic drilling fluid must be carefully maintained, requiring pure clays of predictable chemical and physical properties. The incorporation of so-called natural clays into the drilling mud is no longer a cost saver, but instead the cause for additional, expensive treatments or additives.

In addition, natural clays are taken up from the formations drilled, naturally hydrated, and dispersed into the mud system.


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Stimulant Additives These are chemical additives that dissolve in water or become bound at the active lattice sites on the dispersed clay minerals. Their function is to stimulate and stabilize optimum properties in the drilling fluid: ✔ Carrying capacity - in the circulating fluid, ✔ Gelation - when fluid circulation is halted, ✔ Filtration and filter cake formation - to form the firmest, least permeable filter cake with the least volume of fluid loss. ✔ Flocculation resistance, and so on Alternatively, they may be added to inhibit less desirable tendencies of the mud or natural clays.

Supportive or Reinforcing Additives These are natural organic compounds and synthetic polymers that have some of the same properties as clay minerals and are added to selectively reinforce these properties. For example, starch may be added to improve viscosity and Carboxy-Methyl Carboxy-Methyl Cellulo se , a rapidly swelling but other un-reactive compound Cellulose is added to supplement the mud’s ability to form a is also a common ingredient in various appetite suppressant nostrums. more pasty filtrate which will swell and plug permeability in the bore-hole wall. Barite or Hematite can be added to increase the mud density beyond that possible with clay alone. In a liquid-based drilling fluid system (Figure 2), the fluid is stored in large portable tanks or mud pits fitted with stirrers and jets to keep the complex and thixotropic fluid consistently mixed and un-gelled. From the mud pits, the mud is carried by small centrifugal pumps to larger, high pressure duplex or triplex slush (positive displacement) pumps. The fluid is pumped through pulsation dampeners and then to the rig standpipe. It then passes through a flexible, high pressure, rotary hose to the kelly or rotating power sub, where it is introduced into the drill string and begins its journey to the bottom of the hole. At the drill bit, the properties of the drilling fluid effect cuttings quality by the efficiency with which they are removed from beneath the cutting structure of the bit. In addition to the flow characteristics of the mud, density also has an effect since it is the mud density which provides the hydrostatic head to balance formation fluid pressures. Barite, hematites and other heavy minerals are added to increase the density of the fluid and control subsurface pressures.


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If mud density is excessive, a pressure overbalance exists at the drill bit- formation interface. If this overbalance is too great, it acts to flush drilling fluid into permeability and fractures below the drill bit with engineering and geological consequences. ✔ The overbalance also holds down cuttings on bottom, and below the drill bit, reducing rate of penetration (see Figure 21). ✔ The cuttings spend longer beneath the bit being re-ground to a smaller and less fresh appearance. ✔ Pore fluids are also substantially displaced from the cuttings by filtration of drilling mud. After leaving the drill bit, the drilling mud with its load of drill cuttings and formation fluids travels through the outer annulus to surface. Mechanical abrasion of the rotating drill string, chemical reaction, physical intrusion of drilling fluid, and simple stress relief produce a continuous supply of additional debris from this exposed bore-hole wall. In addition to its load of fresh cuttings, the drilling fluid must also collect and carry this debris to surface. It must also be able, if circulation is halted, to rapidly form a colloidal gel, and suspend the sediment load in the annulus without allowing it to settle. Despite the use of chemical additives, water-based drilling fluids have serious drawbacks. They cause excessive physical invasion and chemical degradation of drill cuttings which can cause geological and engineering problems while drilling. They can cause similar damage to the formations exposed in the bore-hole wall complicating the interpretation of later wireline logs and short- term well tests.

Simple Mud Field Testing Creating a drilling fluid of the perfect composition in a soup bowl is a simple culinary job. Unfortunately, the mud engineer, at a drilling well site, has the additional load of preparing a huge volume of this same composition, while the the bulk of the volume is circulating underground, out of his sight (and his ability to test), and exposed to high temperatures, high pressures, water of various salinities, oil, gases, and chemically reactive minerals. Obviously, teaching the scientific knowledge and engineering skill required to do this job well is beyond the scope of this book. However, there are a few, relatively simple field tests that can be performed on a small sample of drilling fluid, and which provide a basic, general picture of the composition, and condition of the drilling fluid. Such tests are performed routinely (2 or 3 time every day) by a resident mud engineer or (if there is no full time mud engineer at the well site) by the derrickman, or some other rig crew member responsible for monitoring the shale shaker and other mud treatment equipment. The result of these test, in an abbreviated form, should be reported on the mud log, at least once every day, whenever some change in mud chemistry is made, and whenever some significant geological or hydrocarbon event (or show) occurs on the log.


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The mud logging unit should be equipped with the apparatus needed to perform these tests so that, regardless of the presence (or reliability) of the mud engineer, or derrickman, the tests can be run, and the results reported at any significant time. From time If there has been a well kick, or another sign of major fluid influx, then another to time, the mud logger should catch a liter (or quart) cup sample should be taken from the intake line close to the mud pump, so that a of drilling fluid from a freely flowing section of the possum comparison can be made of mud properties going into and coming out of the belly ditch, and perform these tests, as follows.

bore hole.

Drilling Fluid Density or Mud Weight Drilling fluid density going into and out of the bore hole may be measured and displayed automatically by a modern mud logging unit (see Chapter 9, Drilling Data Logging). If not, then manual measurements are necessary (a daily manual measurement on a mud sample taken close to the sensor location is a very useful quality control aid).

Figure 23: Mud Balance (Illustration courtesy Magcobar Div., Dresser Industries) The Magcobar mud balance (Figure 23) consists of a balance beam calibrated in various units of mud density (Specific Gravity, Pounds per Gallon, and so on) and, on the other side of the fulcrum, a cup and lid. To determine the mud density: ✔ Remove the lid from the cup, and completely fill it with fresh drilling mud ✔ Replace the lid, and wipe off any excess mud


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✔ Place the balance arm on the fulcrum ✔ Move the cursor along until the graduated arm until the indicator shows level ✔ Read the mud density from the graduated scale

Funnel Viscosity The simplest measure of drilling fluid viscosity is to use the Marsh Funnel (Figure 24).

Figure 24: Marsh Viscosity Funnel (Illustration courtesy Magcobar Div., Dresser Industries)


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To measure funnel viscosity: ✔ Hold the funnel vertically, with your finger over the bottom outlet. ✔ Pour a sample of fresh mud into the funnel, through the screen. Stop when the level of mud reaches the surface of the screen. ✔ Place a clean empty liter (or quart) sample cup under the outlet ✔ Immediately (do not wait to let the mud settle and thicken) take your finger from the outlet and start the stop watch. ✔ When the mud level in the sample cup reaches the one liter graduation mark, stop the watch ✔ Report the funnel viscosity in seconds per liter (or second per quart)

Plastic Viscosity & Yield Point

Figure 25: Fann V-G Meter (Illustration courtesy Magcobar Div., Dresser Industries)


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The viscosity of thixotropic fluid, like drilling mud, will be higher when flowing, and become progressively lower if the fluid is allowed to stand and gel. A more useful measurement of drilling mud viscosity can be made will little extra effort if a Fann V-G meter (Figure 25) is available. To measure the thixotropic properties of the drilling fluid: ✔ Fill the 300ml container about two-third full with fresh mud sample, and place it under the rotor of V-G meter ✔ Lower the rotor into the mud sample, until the scribe line on the rotor aligns with the surface of the fluid ✔ Turn on rotary motor at the high speed (600 rpm) setting, and wait until the indicator dial adopts a steady value ✔ Record this 600 rpm reading ✔ Turn to the low speed (300 rpm) setting, and wait until the indicator dial adopts a steady value ✔ Record this 300 rpm reading ✔ Calculate the thixotropic values as follows: Plastic Viscosity (centipoise)

=

600 rpm reading minus 300 rpm reading

Yield Point (lb/100 sq ft)

=

300 reading minus Plastic Viscosity

Apparent Viscosity (centipoise)

=

600 reading / 2

Sand Content Most of the solid content in drilling mud consists of finely dispersed clay solids. However, from unconsolidated sediments, a certain amount fine, clastic (sandy and silty) material may enter the mud system, and this material can cause disastrous wear damage to down-hole and rig equipment. When necessary, the rig de-sander and de-silter is turned on the reduce these contaminants. Identification (for geological purposes) and measurement (for engineering reasons) of sand content is easily done using a graduated cylinder, as follows: ✔ Add a small quantity of fresh drilling mud (for example 10 milliliters) and a larger quantity of fresh water (for example 90 milliliters) to a graduated cylinder ✔ Agitate the mixture, allow it to settle, and pour off the turbid water ✔ Refill the container with fresh water, and repeat


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✔ Continue until there remains only solid residue and clear water in the container, and read the volume of solid material from the container graduations ✔ Calculate the sand content (%) as: 100 * Solids Volume / Original Mud Sample Volume

Oil and Solid Content Fann (the manufacturer of the V-G meter) also make a mini-still that can be used to determine, by distillation, the proportions of oil, water, and total solids in a drilling mud sample. As you may imagine, this device should only be used in a well-ventilated, fire-proofed location. It is not suitable for most mud logging units.

Filtrate Tests Most of the other common tests to be run on drilling mud, involve chemical tests or titrations or mud filtrate. To obtain this filtrate, the logging unit should be equipped with a pneumatic filter press. Drilling mud is slow to filter, indeed it is formulated specifically to reduce the volume of fluid that may filter from the bore hole into porous formations. The filter press allows a sealed container of drilling fluid to be filtered under pressure supplied by compressed air. This allows a large enough volume of filtrate to be made available quickly for all of the tests. If the filter press is operated under API (American Petroleum Institute) standardized conditions: ✔ Using a standard volume of mud, and ✔ A standard grade of filter paper, ✔ At a standard pressure, ✔ For 30 minutes Then the volume of filtrate recovered, in milliliters, is standard Filtrate or Water Loss measurement. The thickness of the clay residue on the filter paper, in 32nds inches, is the standard Filter Cake measurement. If you are simply filtering mud in order to obtain filtrate samples for chemical analysis, then you need not comply with these standards. The tests that can be performed on mud filtrate include: ✔ Acidity-Alkalinity, using titration, a pH meter, or pH test paper ✔ Salinity (or Chlorinity), using a silver nitrate titration ✔ Hardness, using a versenate titration


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Whole mud may also be subjected to a methylene blue test to determine its Cation Exchange Capacity, a measure of the relevant amount pure bentonite clay, and formation clays in the drilling fluids. These and other chemical analyses are discussed in more detail in Chapter 7: Geological Evaluation – Lithology & Mineralogy.

Oil-based Muds Some water-based muds may contain traces of natural (petroleum or vegetable based) or synthetic oils. The small amount of dispersed or emulsified oil is added for its lubricant properties to prevent or reduce sticking or friction on the bore hole wall. Other, truly alternative liquid drilling fluids are based upon oil, and oil-and-water mixtures: ✔ Oil-based mud may contain only a tiny percentage of dispersed natural formation water or, ✔ If more water is present, it may be held in the form of a water-in-oil as an invert emulsion Because the water is present only as a non-continuous phase of droplets it cannot react with the formation as aggressively as a true waterbased fluid. Similarly the naturally high viscosity and stability of the invert emulsion limits the invasion or filtration of mud or mud filtrate into formation permeability or fractures. Oil-based fluids are generally more inert and less reactive to cuttings and the bore hole walls than waterbased drilling fluids. The earliest oil-based drilling muds used crude oil or bunker fuel but these were unsatisfactory. The inhomogeneity and impurity of the base oil made the fluids unpredictable in behavior and in their response to treatment additives. Furthermore the toxic and polluting nature of the fluids caused serious problems in using and disposing of the fluids and cuttings contaminated with them. Modern oil-based drilling fluids use synthetic, vegetable-based, or highly purified mineral oils. The purity of these fluids allow reliable and predictable use. Because they are biodegradable and low in toxicity they are also less hazardous to work with and easier to transport, store and dispose of. Modern oil-based drilling fluids are efficient, controllable, inert and non-invasive. They produce good quality, fresh cuttings with little invasion, hydration or degradation. On the other hand these fluids can be very confusing in oil evaluation. Just like natural kerogen, the oil-based muds can will be cracked to form other hydrocarbons under the effect of the high down-hole temperatures and the catalytic action of the formation clays. Oil-based mud is also an excellent solvent for hydrocarbon oil and gas and other organic material from all origins. So that, having drilled a few thousand feet, the oil-based fluid will be carrying remnants of all of the organic material encountered so far on the well. It is also actively generating hydrocarbons on its own. If the drilling fluid is re-used on subsequent wells (which it probably will be, because oil-based fluids are expensive to make, and expensive to dispose of) the contamination problem becomes progressively greater.


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Interpreting a newly encountered oil show, against such a background, consisting of oil-base, various decomposition products, and traces of every hydrocarbon previously encountered on this and prior wells, can be a serious headache! This is discussed in Chapter 8: Hydrocarbon Evaluation – Oil, Gas, & Precursors. Finally, if an oil-based mud is to be used, and washed-and-dried cuttings sample sets are to be collected, then a well-ventilated, fire and explosion-proofed, sample processing building will need to be set up (and, if necessary, certified). An occupied mud logging unit is not the place to be heating cuttings samples containing oil-based compounds, or containing remnants of the solvents used to rinse out those compounds!

Gas-based Dusting Gas-based, or dusting, drilling fluid systems are generally similar to drilling mud systems with certain obvious differences (see Lorenz, 1980). In the past, dusting was often accomplished using natural gas from a conveniently located pipeline. Today, this is rarely economic and the gas most often used is compressed air. Oddly enough, the major disadvantage of this change is the risk of underground fires! Previously, when you drilled into a gas-bearing formation, mixing its output with other hydrocarbons has little effect. On the other hand, mixing formation hydrocarbons with hot, turbulent, compressed air yields a highly combustible mixture. Air drilling requires, powerful compressors to be available at the well site (Figure 26) taking the place of the drilling mud pits and pumps. With minor differences, the compressed air circulation system is analogous to the mud system until the top of the annulus is reached. The circulating air stream imposes little or no hydrostatic pressure on the bore hole bottom and walls, and so the air-drilled well requires the annulus to be sealed at all times. Unfortunately, drilling cannot be carried out with conventional blowout preventers closed around the drill string. A rotating drilling head closes around the drill string much like a blowout preventer, an internal swivel and allowing a small amount of leakage for lubrication, the drill string is free both to rotate and move up and down through the drilling head. Obviously, large objects such tool joints or a drill bit cannot pass through the drilling head. For tripping or making connections, circulation must be stopped, the drilling head opened and a jet of compressed air in blown across the top of the bore hole to carry away dangerous produced gases. Equally obviously, this type of drilling operation is most convenient when drilling without a heavy drilling fluid yields great improvements in rate of penetration, but when there is also very little risk of massive, combustible, or explosive fluid influxes. For example, when drilling impermeable, hot, dry rock geothermal wells. While drilling, the exhaust air, the cuttings and produced formation fluids are diverted from below the drilling head through the blooie line to a safe distance from the rig. Toward the end of the blooie line there may be a de-duster and a flare. The de-duster is a water injection system that prevents air-polluting dust emissions. The flare is ignited if the air stream is carrying combustible hydrocarbons. Extra air and natural gas is injected into the blooie line to ensure continuous full combustion at the flare pit located at the safe end of the blooie line.


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Figure 26: The circulation system required for a gas-based drilling fluid system: gas (usually compressed air), mist or foam. Dusting allows the fastest possible rate of penetration due to the complete absence of a hydrostatic head in the annulus. Unfortunately, the explosive decompression of material fractured by the drill bit blasts them into minute fragment. The turbulence and high velocity of the air flow in the annulus causes many more collisions between the cuttings, the bore hole wall and the drill string. When the cuttings are sampled by the geologist at surface, he quickly understands the significance of the term dusting — the so-called cuttings are little better than dust. A disadvantage of air-drilling and one that has prevented it being widely used in large-hole drilling is that the drilling fluid is incapable of


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carrying large cuttings loads or of suspending cuttings when circulation is halted. Water influx may also be a problems resulting in the cuttings becoming a swollen pasty mass that is of little geological value, and worse it can plug up the entire circulation system.

Mist and Foams The mixing of soap with the air stream was first introduced to solve the water influx problem (Linicome, 1984). In this process, droplets of soap solution are carried into the drill string as a mist, and then mix with formation waters in the annulus to produce foam. The process is therefore in some areas known as misting and in others as foam drilling. True foam drilling was first used at the Nevada Nuclear Test Site to drill extremely large diameter hole into dry porous formations. These wells required recovery of a large volume of cuttings without using a dense liquid or mud slurry that would create a pressure overbalance, invade, and damage to sensitive, low pressure, dry formations. Stiff foam, or A.E.C. foam as it was sometimes called, is a mixture of very low density clay-water drilling mud with a surfactant which is prefoamed prior to injection into the bore hole. As a mixture of water-based mud and air, it had hybrid properties between the two. It produces only a small hydrostatic head in the bore hole but has more stable, lower velocity fluid flow rates in the return annulus. Drill cuttings produced in foam drilling are fine grained, and have an explosive appearance but are not so extensively damaged and ill-sorted as those produced in a conventionally air-drilled well. Stable foam is a newer drilling fluid, consisting of a mixture of: water, air and a non-ionic surfactant. It has the consistency of shaving foam (or the kind of foam laid down by fire fighters) and is extremely stable unless mixed with relatively large volumes of water, when it relaxes rapidly to a thin watery solution and releases its large sediment load. Stable foam allows low bore-hole hydrostatic pressures, and extremely high rates of penetration. Cuttings although small are well suspended by the stable foam which is inert, non- invasive and travels at velocities only slightly higher than that of drilling muds. Stable foam may become the drilling fluid of choice in those many drilling applications where high overbalances are not wanted and pressure control is not a problem, for example, in very hard, and subnormally pressured rocks.

Coring Coring (see Whittaker (Ed), 1985) is, in every consideration, the superior method of obtaining rock samples from a well bore It allows the geologist to observe the true nature and orientation of rock structures and textures in reliable, unmixed and un-worked depth relationships (although not in real time). It can also provide samples of rocks, minerals, hydrocarbons, and pore waters of suitable quality for geochemical, petro-physical and rock mechanical analyses, that are far less contaminated or disturbed than any other source. The simplest coring method uses the standard bottom-hole core barrel (see Figure 28) and core bit (see Figure 27).


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Bottom-hole Coring The core bit (see Figure 27) is similar in appearance and function to a diamond or PDC drill bit except for the large central opening. The bit cuts a narrow annular ring, or kerf, of formation, allowing a cylindrical core of rock to pass upwards into the interior of the drill string. Coring and core recovery has been found to be most successful when kerf diameter is of the order of half of bit diameter. The most common standard core bit sizes are 215 to 250 millimeters (8.5 to 9.75 inch) which cut 90 to 115 millimeter (3.5 to 4.5 inch) diameter cores. After coring it may be necessary to ream the core hole out to the larger diameter of the preceding drilled section of the bore hole before drilling ahead.

Figure 27: The Core Bit or Core Head is Similar in Design to a Diamond or P,D.C. Drill Except for the Central Opening for Entry of the Core into the Core Barrel (after Christensen Diamond Products, used with permission)


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Figure 28:The Conventional and wire-line recoverable core barrels are similar in design and function.


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The wire-line inner core barrel is smaller in diameter to allow retrieval through the entire drill string. The conventional core barrel (see Figure 28) is located immediately above the core bit. There are in fact two core barrels: an inner, non-rotating, thin-walled barrel which captures and holds the core after it passes through the core bit, and an outer heavy, thick-walled barrel which protects the inner barrel and takes the place of the bottom-most drill collar. Circulation of drilling fluid is initially through the inner barrel but, once coring commences, a ball is dropped from surface, down through the drill string. The ball settles in the check valve at the top of the inner core barrel, diverting the fluid between the inner and outer barrels so that fluid flow does not erode or displace core from the inner barrel. Coring is carried out in the same manner as drilling but more slowly and carefully since any violent action or sudden change in pipe motion can result in the core breaking and falling from the barrel, or jamming the barrel to prevent any more core from being cut. When the barrel is filled, or if core jamming halts the process, the entire drill string must be pulled from the bore hole in order to recover the core. Conventional core barrels are commonly manufactured in 10 meter (32 feet) long sections which can be run in double or triple combinations. Unfortunately, the longer the core barrel assembly becomes the more difficult it becomes to vertically stabilize the thin-walled inner barrel, and flexing of the barrel causes core breakage and jamming. Practical considerations usually limit core barrel length to 30 meters (100 feet) for successful coring. Obviously, in very deep wells, the core barrel length limitation can making extensive coring impractical. Drilling costs escalate as time spent coring is outweighed by the time spent tripping coring assemblies in and out of the hole. Worse, the risks of bore hole damage, core bit or barrel damage or core loss becomes greater because of these large numbers of trips. Conventional coring is therefore reserved for wells in which only limited depth ranges need to be sampled. For example, detailed evaluation of previously discovered reservoir intervals. In research drilling, where long sections or even the entire well must be cored, a more efficient method must be found for recovering core from the well without removing the drill string. This is done by using a retrievable inner core barrel. The retrievable inner core barrel may be conventional in design except that it is not permanently attached but is held in place in the outer barrel by the hydraulic force of the circulating drilling fluid. After the retrievable core barrel is filled with core, the inner barrel can be recovered back to surface through the drill string on a wire line equipped with a grapple. After recovery of the core barrel from the top of the drill string a replacement can be pumped down to the bottom of the drill string and coring repeated. Use of a retrievable core barrel allows coring to be carried out almost continuously or at least until the long-lived diamond or PDC core bit is worn out and needs replacement. The disadvantage of continuous coring is that, in order to pass freely through all of the components of the drill string, the retrievable inner barrel must be smaller than an equivalent conventional inner barrel. As a result, continuous cores are smaller, commonly no more than 50 to 75 millimeters (2-3 inch) in diameter. They also have a larger bit diameter-to-kerf ratio, about 3:1, and have generally less successful recovery factors than conventional cores.


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Continuous cores are comparable to conventional cores for many geological purposes. However, for chemical or mechanical measurements, they are more likely to be contaminated, eroded by drilling fluid or mechanically damaged and therefore provide less reliable samples than conventional coring.

Specialty Core Barrels Another difficulty in coring involves unconsolidated rocks and sediments. These may be excessively washed in the barrel or simply collapse and fall out of the barrel as it is recovered to surface. Even if recovered successfully, it may be impossible to remove an unconsolidated core from the inner barrel without destroying it and obtaining only a heap of loose sediment.

Figure 29: Inner-sleeved core barrels can be used to improve core recovery from fractured, unconsolidated, or very brittle rocks likely to broken, jammed or lost from the core barrel.


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To aid in this problem, the inner-sleeved core barrel (either conventional or retrievable) may be used. In the most reliable form of this device, a flexible rubber sheath is extruded over the core as it enters the inner core barrel (see Figure 29). This sleeve encloses and grips the core securely guarding it from either fluid erosion or physical collapse. Containment in the sleeve also allows the core to be removed from the barrel in one piece without breakage. The sleeved core can be cut into smaller section for evaluation. Before sectioning for visual examination the entire core can be artificially consolidated by freezing or impregnation with a plastic gel. A simpler alternative method, requires no special equipment other than a slightly over-sized inner core barrel. A rigid PVC liner is installed into the inner barrel before core commences. The core passes into the inner barrel and is protected by the PVC liner. This does not provide such secure protection as the flexible sleeve but it is simpler, more convenient and less subject to problems. On recovery to surface, the core is removed from the barrel in its liner and sawed horizontally and vertically into convenient sections for evaluation. A major value of core samples is the internal consistency of structural and fabric orientations. Within any section of core (or a whole core if the pieces can be re-oriented to each other) all dips and strikes can be correlated with each other — unlike the randomized orientation of textures in well cuttings. Of course, this value would be significantly enhanced if core orientations could be correlated with a real world threedimensional coordinate system. This is not possible in any of the coring equipment discussed so far. In each of these, the orientation of the core to the bore hole is unknown and the inclination and azimuth of the bore hole itself are not known with any certainty (Nelson, Lennox, and Ward, 1987). An orientation assembly can be relatively easily added to most core barrels. Strangely, it is an improvement which is often overlooked. The orientation assembly consists of modifications to the bottom and the top of the inner core barrel. At the bottom of the barrel a blade is attached which scribes a groove onto the core as it enters the barrel. This scribed line allows all pieces of recovered core to be later aligned with each other and to the inner barrel. A directional measurement and recording system is mounted at the top of the inner barrel and locked to it so the they remain aligned even if the inner barrel rotates during coring (see Figure 30). The directional system used may be one of the several types used to measure bore hole inclination when drilling directional oil wells. Throughout the coring operation measurements are taken of the inclination and azimuth of the inner core barrel. After the core and the recorder are recovered from the hole the core and its internal structures can be oriented with real world coordinates. The final weakness of conventional coring methods is the uncertainty introduced by the rapid removal of the core from its high temperature, high pressure, in situ environment to surface temperature and pressure. The process of coring itself subjects the rock to removal of normal overburden and significance mechanical stresses, shocks and vibration. Pore fluids, if present, may be displaced into or away from the bore hole by drilling fluid depending upon the degree of differential pressure across bottom. While much less than the equivalent effects on well cuttings, these may still be considerable. Recovery to surface results in a further reduction in confining pressure on the matrix and formation fluids and a rapid reduction in ambient temperature sufficient to induce further shock to the core. The combined effect of all of these changes is to complex to be reliably modeled However, two types of specialized core barrel provide assistance in removing or solving the problem.


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Figure 30: In the oriented core barrel, a steel blade scribes a groove on the core as it enters the barrel. Later, the scribe line on the core can be aligned with drilling depth and bore-hole directional measurements.


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Figure 31: The foam-lined and pressurized core barrels offer a way to capture or retain formation fluids from the cored formation when it is returned to surface.


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The sponge-lined core barrel is primarily intended to trap for analysis formation fluids in sedimentary rocks which otherwise would be lost during recovery, due to gas dissolution and expansion, followed by water and oil expulsion. It resembles a conventional core barrel with an expendable, perforated inner sleeve made of aluminum lined with an absorbent sponge material. This material traps water and oil expelled from the core as it is recovered to surface (see Figure 31). When the core barrel is returned to surface, the entire inner assembly is removed, cut into sections and each section (rock, foam and aluminum tube together) is sealed for later analysis. This provides a major improvement to sample quality when sedimentary pore fluids and organic geochemistry are the objects of study. The system obviously yields no improvement in rock mechanics and structural work. A more sophisticated method is required to assist in these and other hard rock studies. The pressure core barrel is again similar to a conventional core barrel except that the inner barrel is equipped with a pressure seal at its top and a large ball valve at the bottom through which the core may pass while coring is underway. When coring is complete and the core barrel is lifted off bottom the ball valve closes, shearing the core and sealing it within the barrel. The core barrel is then recovered to surface with nitrogen from a pressure reservoir entering the inner barrel at a regulated pressure to counter the effects of cooling. On surface, the entire inner barrel is immersed in dry ice for several hours until frozen. When frozen, the nitrogen pressure is bled off and the barrel and the contained core is cut into sections, repacked in dry ice and removed for analysis. Because of the space requirement of the pressure seals, the core from a conventionally sized pressure barrel is shorter and smaller in diameter than that from a conventional barrel. However, this loss in size is compensated for by the much greater quality of sample recovery.

Wire-line Coring Continuous bottom hole coring is the ideal method of subsurface exploration. Unfortunately it is also slow, expensive and can be the cause of hole problems or stuck drill pipe. Furthermore coring is not always successful: the core may be eroded, damaged or lost from the core barrel on recovery. An alternative is required when bottom-hole coring is ruled out by economics or hole problems or to replace lost core after the well has been drilled. This alternate is provided by sidewall coring: cutting a short, smalldiameter core in the wall of an already drilled bore hole. The oldest type of sidewall coring device is a rotary device that protrudes at an angle from a conventional drill string. This method is hardly satisfactory since it involves many of the time, cost and bore hole damage problems of conventional coring. Most modern sidewall coring is now accomplished by tools run into the hole on a logging wire line and controlled by signals from the wire-line logging unit. Technologically, and in terms of the service companies involved, sidewall coring on a wire line belongs later in this book, along with wire-line and MWD logging. Nevertheless, geologically its at home here, where we have already discussed the methods of recovering cuttings and conventional core samples.


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Figure 32: The Chronological Sample Taker (CST) or wire-line sidewall coring tool. The Chronological Sample Taker (CST) is more commonly called a sidewall core gun. The gun (see Figure 32) contains several (12, 24 or 30) bullets mounted horizontally and attached to the gun by braided wire fasteners. The tool is run into the bore hole on a logging cable to a zone of interest. At that depth, a signal is transmitted to the gun and an explosive charge is ignited to fire one of the bullets which hits and penetrates the bore hole wall. The gun is then moved upward on the logging cable and the bullet, on its wire fastener, is jerked out of the bore hole wall with small core contained inside its hollow center. The gun is moved up to the next zone of interest and the process repeated. On surface, the cores are pressed from the hollow bullets and packed in glass jars for later examination. The sidewall core gun can sample a very long section of formation very rapidly and economically. It is simple and reliable in operation. Using several guns in combination on a single run, it is possible to obtain 70 or more cores allowing for spare shots to replace misfired shots or provide duplicates of specially interesting zones. The disadvantage of cores obtained by the sidewall core gun is that they are very small and very poor quality. While useful for visual evaluation, they are of little value for quantitative analyses of structure, mechanical properties or contained fluids. The core are small: 25 millimeters (1 inch) in diameter and a maximum of 65 millimeters (2.5 inch) long. If the bore hole wall is irregular or eroded, the annular radius may exceed the length of the wire fastener so that the bullet cannot fully penetrate the wall and only a partial core is recovered. In very hard rocks, incomplete penetration or bullet breakage may also result in recovery of cores of less than the maximum length. On the good side, it is usual, when core recovery is less than a certain percentage for


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the contractor to offer refunds or free re-shots. This is unusual in wire line services, operations where the customer is normally responsible for all cost of equipment and services whether successful or failed.

Figure 33: The Hard Rock Coring Tool (HRCT) or rotary sidewall corer Even when fully recovered sidewall cores are often of poor quality. They are taken from the zone of formation adjacent to the bore hole which has been exposed to physical damage from drilling and impacts of the drill string. This zone is also extensively contaminated with drilling mud filtrate and the physical effects of the hydrostatic overbalance. Finally the cores have been subjected to the mechanical shock of the bullet impact and removal. It is unlikely that the chemistry and mechanical properties of the core are likely to be truly representative of those of the undisturbed rock. An alternate type of wire-line sidewall coring is becoming more common. As its name suggests, the Hard Rock Coring Tool (HRCT) (Figure 33) is primarily intended to overcome the problem of bullet breakage and incomplete penetration in very hard formations. This is accomplished by using an electrically powered diamond core drill in place of the explosively fired gun. In practice, the HRCT has been used in wider range of hard, less hard and porous formations resulting in good recovery and less mechanical compaction damage than seen in sidewall gun cores. The HRCT is lowered into the bore hole on a logging cable to the desired sample depth. At this point, a backup shoe is extended to force the


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core drill side of the tool against the bore hole wall. The core drill is activated, cuts and withdraws a horizontal core of approximately 25 millimeters (1 inch) diameter and up to 50 millimeters (2 inch) long. The backup shoe is withdrawn, the core is pushed out of the core drill into a receiving chamber and the tool is moved to the next coring location.

Figure 34: The TriCore core slicing tool There is another, very different, wire-line sidewall sampling tool which is very effective in hard and fractured rocks but is otherwise not widely used. This is the TriCore core slicing tool (Figure 34). The TriCore tool is run on a logging cable and set with a backup shoe to place it against the bore hole wall. Two circular diamond saws, angled toward each other, at about 60 degrees, extend from the tool and move downwards making two cuts down through the rock each about 40 millimeters deep. Because of the set of the two saws, the two cuts are approximately 40 millimeters (1.5 inch) apart at the bore hole wall and meet at their tips, thus the saws cut a slice of rock, triangular in section, approximately one meter (3 feet) long with tapered ends where the saws extend from and retract back into the tool. The rock slice falls down into a catcher and the tool can be moved to a new location for another sample. The TriCore samples are small in section and taken from the zone adjacent to the bore hole. In irregular, washed-out boreholes the slice will be irregular and discontinuous. Such samples, especially of softer, friable rocks, will be broken, disordered or even pulverized on recovery.


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For these reasons, the TriCore has had little success in commercial exploration for oil and gas in young sedimentary rocks. On the other hand in hard, low permeability rocks bore hole wall damage and contamination is slight and the TriCore sample will be whole and not subject to damage in recovery. In these circumstances the TriCore tool can provide a relatively long (one meter, or three feet) continuous sample of the rock.

Core Logging Mud logging is a real-time activity. It is part of a well-planned drilling operation. The physical nature and appearance of drill cuttings strongly reflect the type and style of drill bit and the drilling fluid used to produce them. Similarly, the nature of the formation being drilled will effect the speed and efficiency with which drilling takes place. In order to really understand the nature of the formations penetrated, cuttings descriptions and other lithology logs must be combined with an understanding of the drill bit, drilling fluid and the drilling methods used. Involvement of mud loggers and geologists in the well planning process can assist the drilling engineers in selecting the most efficient drilling tools. In return, this involvement may allow the geologist’s voice in the selection of the type of drill bits that will produce the best sample quality without being detrimental to drilling progress and safety. Mud loggers are usually delegated the task of recovering, sampling and packaging cores. At the same time, they will usually add to the mud log a brief description based on viewing the core. If they don’t, then they should be reminded to do so. Coring proceeds slowly and only a slim kerf of rock is cut by the crushing diamond bit cutting structure. The result is that cuttings samples collected while coring are limited in both quantity and quality. Unless a description of the core is added to the mud log, then the data for this very important interval is probably of little value. Wire line service company personnel at the well site are usually electronic or petroleum engineers. It is therefore common for the mud loggers to make the first appraisal of sidewall cores and to add brief descriptions in pigtail report attached to the bottom of the mud log (see Chapter 11: The Basic Mud Log). This is useful at the time, allowing the mud loggers a better understanding of the in situ nature of the rocks they have seen in well cuttings. Later, the pigtail on a mud log from the log library may provide useful information not otherwise available.


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And Next ... In this Edition Now we are qualified to look at mud logging and to begin to make sense of the measurements being made and conclusions drawn. In Chapter 5 we shall begin with the most basic form of mud logging: detection of total combustible hydrocarbons in the mud stream. We shall then add to that, by looking at detection techniques and diagnostic significance of the individual volatile alkanes. We finish with detection methods for synthetic gases used as lag time tracers, and the geo-chemically important polar gases.

... On the List Things we didn't get to in this edition include:

Stuck Pipe When a vertical exploration bore hole is drilled, the drilling program usually includes “straight-hole” requirements. ✔

These provide that the entire well, top-to-bottom, must stay within some defined vertical cone. This ensures that the selected targeted horizons will be penetrated at appropriate (and known, or calculable) depths

✔

The requirements also specify that at no place can the vertical inclination of the well bore change more than specified number of degrees in any 100 feet, or 100 meters. Too great a change in bore-hole angle over a short vertical length is called a dog-leg. If it occurs, the the bit must be pulled back and reamed down to produce a smooth, vertical bore hole. Flexible drill pipe rotating through a dog-leg will progressively wear a groove into the high-side of the bore-hole wall with a smaller diameter than bore hole itself. This is called a key-seat. ✔ If a rigid drill collar is pulled upward into a key-seat, it may become jammed in place, causing the drill string to become stuck or, if over-pulled, to break, or, if over-rotated, to twist-off. ✔ More flexible drill pipe, when pulled into a key-seat, may become stuck against a porous, and permeable formation with a lower formation pressure than the adjacent drilling fluid column. This is called differential sticking.


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✔ If the formation in the key-seat is hard and abrasive, then the continual wear on the drill string passing, and rotating, through it can cause the pipe to leak drilling fluid and eventually to break. When the drill string does get stuck in the bore hole: ✔

By pulling and then slacking off the drill string, the driller can estimate, from the change in drill string weight, approximately at what depth the drill string is stuck. If that isn't possible, then a free-point indicator can be run on a wire line inside the drill string. This tool contacts the inside wall of the drill string and monitors changes in stress as the drill string is pulled or rotated. The free point, is that point below which such changes can no longer be detected.

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A slug or pill of oil mud, or some lubricant additive, is mixed up and pumped a calculated number of strokes down the drill string and back up the annulus to the exact spot where sticking is suspected. There it is left to soak, and periodically the drill string is gently pulled or rotated, in an attempt to free it. This is called spotting and soaking.

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If the drill string cannot be freed, then it is necessary to counter-rotate the drill string in order to unscrew, or back-off, the lowest free tool joint and pull out of the hole for a fishing job.

Fishing When part or all of the drill string is broken, lost, or left behind in the boreholes, then it is necessary to fish for it. There are various kinds of fishing tools for: ✔

Retrieving a lost, broken or stuck section of drill string, there are various types of spear, over-shot, wash-over tools to latch onto, (or into) the drill string fragment, and jars that can jerk the drill string sharply upward or downward, to free it from the bore hole, and firmly grip it for retrieval from the hole. If jarring fails to free the drill string then an explosive string shot can be run into the pipe, down to the free point and fired while the pipe is being pulled or counter-rotated.

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For retrieving junk or smaller debris from the bore hole, a junk or boot-sub is used to stir up the bottom of the bore hole and throw up the debris into a catcher or basket immediately above. This tool is of interest to the geologist or mud logger, because it may sometimes pick up, larger, undisturbed samples of bottom hole formations. A core-barrel-style junk basket may also be used to cut a short core at the bottom of the hole, along with any debris on it. This tool too is also of interest to the geologist or mud logger. Plan to be on the rig floor when it is retrieved.


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Alun Whittaker

✔

After a fishing run has been completed, a solid mill bit may be run in order to grind up any remaining debris along with large magnet to collect and and carry out the junk.

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A grapple or or rope spear may be used to retrieve lost sections of wire line from the bore hole.

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If a fish cannot be removed from the bore hole, then it must be cemented in place and the hole re-drilled around it.

Directional Control When drilling a vertical well, rigid drill collars, with appropriately place stabilizers ensure that the well continues or a straight, and vertical path. Measurements of vertical inclination can be made used a drift survey tool (commonly called a Totco recorder): ✔

This a slim, aluminum cylinder with rubber stabilizers, appropriately sized to fit neatly inside the drill pipe and drill collars in use.

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Inside the cylinder is a needle pendulum balanced on a pivot. The pendulum swings on the pivot, so that the needle always points vertically upward.

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Above the needle is a paper disc, marked with circles graduated in degrees (or fractions of a degree).

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The tool can be run into the drill string to bottom on a wire line, or it can be dropped into the drill string and allowed to fall (or it is pumped) to bottom.

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After a proper time interval (for the tool and pivoted needle to come to rest) a timer releases the paper disc, which falls onto the needle, and a hole is punched showing the angle of the axis of the bore hole from vertical. In more sophisticated versions, the chart is then lifted, rotated 180 degrees, and dropped again, so that a second, confirming, pin hole is made.

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The tool can then be pulled from the hole on a wire line. More commonly, the tool is dropped into the drill string when it is time to change the drill bit. It can then be left in place, and retrieved when the drill string has been tripped out of the hole.

A more sophisticated version of the tool uses a pin-point light source and photographic film, allowing several measurements to be made at different depths, on a single run in the hole. If a monel metal, non-magnetic drill collar is used immediately above the drill bit, then the survey instrument can be magnetically oriented, so that both the angle and direction of inclination can be measured.


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Alun Whittaker

If a vertical well becomes too deviated then it must be plugged back with cement and re-drilled. On the other hand, wells may be intentionally deviated in order to: ✔ Reach targets that are inaccessible from a vertical well. ✔ To allow drilling a large number of producing wells to be drilled from a rig on a fixed offshore platform, or in a congested urban location. ✔ Perform well control on a well that is blowing out, or on fire ✔ To create a longer producing interval in the well from a relatively thin productive horizon. Such long-reach wells may even be drilled semi-horizontally following the same producing horizon. Obviously this introduces unique challenges to mud logging when, for example, trying to remain in the oil bearing horizon, and not penetrating upward or downward into non-productive zones. There are numerous tools and techniques available for controlled directional drilling: ✔

Probably the oldest, and simplest of these is the whipstock, a large metal wedge lowered to the bottom of the bore hole, and oriented to push off the bit in the desired direction.

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In softer formations, the directional offset can be started using a tri-cone bit with one jet that is larger and extended. With the drill string stationary, this jet is used to wash a cavity in the bore hole wall. Then rotation is started and the bit moves off, hopefully, in the planned direction.

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Modern directional drilling is carried out using a bent sub located a short distance above the drill bit, and oriented in the correct direction. The drill string is not rotated, but is lowered steadily as a mud turbine or moinneau-type down-hole motor (below the bent sub) turns the bit. Hole angle is built progressively as the hole is deepened. When the necessary angle has been built, the assembly is removed and replaced with a conventional drill string.

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When the required angle and direction have been achieved, design of the bottom hole assembly – number and size of drill collars, placement of stabilizers – and using the appropriate Weight on Bit can be used to maintain, build, or drop off hole angle.

Most recently, sophisticated measurement while drilling tools have been developed to continuously measure bore hole inclination and direction and even, if necessary, to provide continuous down-hole steering. Some of these are discussed in Chapter 10. None of these activities are part of the mud logger's job, but they form part of his working environment. They yield information that he may need to know, and may need to record on the mud log. Hopefully, we will be able to include more about them and other well-site technologies in later versions of this chapter.


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Rotary Drilling

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