Basic Drilling Technology

CONTENTS

CONTENTS 1.

INTRODUCTION

2.

INTRODUCTION TO DRILLING TECHNOLOGY WELL PLANNING

3.

WELL PLAN

4.

TYPES OF DRILLING UNITS

5.

THE RIG

6.

DRILLING ASSEMBLIES

7.

DRILLING FLUID

8.

DIRECTIONAL DRILLING

9.

CASING AND CEMENTING

10.

DRILLING FROM A FLOATING VESSEL

11.

INTRODUCTION TO PRESSURE CONTROL

12.

GLOSSARY

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CONTENTS

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INTRODUCTION

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INTRODUCTION

1.1

GENERAL This manual is intended for use as student material for the introduction to drilling equipment and practices course given by Downhole Technology. However it is hoped that it will also be a useful and interesting document for stand-alone use. The material contained is of a basic nature and tries to avoid, as far as possible, the use of oilfield jargon or complicated formulae. This means that people requiring a broad overview of the drilling industry and those embarking on a drilling career, can grasp the key concepts involved in drilling a well without becoming bogged down in technical information. Whilst every attempt has been made to ensure the accuracy of the information no responsibility is accepted for inaccuracies contained herein. However, should you have any suggestions for update, these will be gratefully received.

1.2

SPECIFIC OBJECTIVES At the conclusion of this training course, the delegate will be able to: · · · · · · ·

Identify different rig types and the application of each. Identify the individual components of a drilling rig and drilling string and understand the function of each. Understand the concepts of directional drilling and co-ordinate systems. Read a well plan and produce a simple casing design. Identify the equipment involved in pressure control and perform simple well control calculations. Identify the components and understand the concepts used in floating drilling. Understand the reasons for well testing and completion and have a basic idea of the equipment used.

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INTRODUCTION

1.3

THE STORY OF AN OIL WELL

1.3.1

Drilling To retrieve hydrocarbons trapped deep below the Earth's surface, a hole has to be drilled into the ground allowing the oil and gas to come to the surface, under their own pressure or pushassisted. To this end a Drilling Rig is used to drill the hole, the drilling rig is, for all practical purposes, a vertical crane. This vertical position enables the maximum amount to pull available from the main drum called the ‘Draw-Works’ located on a rigid platform called the "Rig Floor". The hole is drilled by using a rotating drill bit of a specific size, the first size used is large, from 17 1/2" to 36", and each bit is reduced as the hole gets deeper. The drill bit is rotated by means of either a rotary drive table and "Kelly Drive Bushings" integrated into the rig floor, or a top drive system built into the main lifting mechanism. The rotational speed is adjustable to allow for variations of torque depending on the types of formation that is being drilled through. This is used in conjunction with the amount of weight that is present on the drill bit, supplied by the drill string and controlled by the draw-works. The drill string consists of hollow tubular pipes, threaded at either end to enable easy connection to each other and varying in length between 25 to 40 ft. The tubulars at the bottom of the string, nearest the bit, are the heaviest, creating a pendulum effect to keep the bit directionally under control, these are called Drill Collars. These are connected to an intermediate type of tubular called Heavy Wate Drill Pipe, which, in sequence is connected to Standard Drill Pipe. The heavy wate drill pipe is the intermediate step between the drill collars and the drill pipe so as not to create a weak point at the change of pipe weight. The drill string also carries stabiliser joints, called subs, theses are short, bladed joints whose diameter is the same as the drill bit, these subs keep the drill string connected to the bit and also aid in directional control. During the drilling process a fluid is pumped down the centre of the drill string, this fluid is called drilling mud, these fluids do many jobs, they cool the bit and bring cuttings to the surface. Depending on the type of chemicals in the drilling fluid it can also coat the inside of the well bore, gel to a near solid state when circulating ceases to stop cuttings falling and gathering around the drill bit, and weighting the chemicals to create hydrostatic head in the well bore to stop any formation fluids, or gases, migrating to the surface during drilling operations.

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INTRODUCTION

1.4

CASING AND TUBING The well is drilled in sections, the first being the largest diameter, after the section is drilled the hole is "Cased" with steel liner pipe called Casing. Again, this pipe is supplies in short lengths, 30 to 50 ft, and is threaded at both ends; this is lowered, not drilled, into the finished section and is smaller in diameter than the well bore. When this pipe is in place inside the well, a cement is dried the casing string is pressure tested to ensure it is safe against formation fluids migrating to surface, known as a ‘Kick’ or ‘Blow-out’, the section is then drilled using a smaller drill bit. This drill bit is conveyed to the bottom of the hole through the casing in place and is smaller in diameter than the inside diameter of the casing. Generally casing is run from well bottom to the ground surface, but the cement may not be pumped all the way to the surface, just pumping the amount needed to cover the bottom part of the well which is open to the formation. Eventually the depth is reached where it is known or surmised there are hydrocarbons present, at this point a small diameter, 1.66" to 4 1/2", Test String is temporarily run to allow controlled release of the formation fluids to test the amount of hydrocarbons recoverable. Or, a similar diameter Completion string is run as a permanent conduit for the production of the formation hydrocarbons.

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INTRODUCTION

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INTRODUCTION TO DRILLING TECHNOLOGY WELL PLANNING

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INTRODUCTION TO DRILLING TECHNOLOGY WELL PLANNING

1.1

INFORMATION REQUIRED BEFORE DRILLING COMMENCES

1.1.1

Seismic Data · Wildcat wells are seldom drilled without preliminary seismic work being done in the area of interest. Proper analysis can be used in predicting the pore pressure to be encountered. · The techniques are similar to acoustic well logging, but use different frequencies. Spread

Survey ship

Shot

Radar Reflector Tail Marker Sea Bed

Hydrophone Cable (Seismometer)

Marine Reflection Shooting

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INTRODUCTION TO DRILLING TECHNOLOGY WELL PLANNING

1.1.2

Data

EXPLORATION

SEISMIC DATA

PORE PRESSURE

FRACTURE GRADIENT

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MUD PLAN

CASING DESIGN& SETTING DEPTH

CEMENT DEPTH

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INTRODUCTION TO DRILLING TECHNOLOGY WELL PLANNING

1.1.3

Drilling Programme

AFE

Well Plan

NPT

Casing Programme

Rig Selection

Lithology Plot

Reservoir Evaluation

Land Rig

Semi-Submersible

Jack Up

Drill Ship

Evaluation

Logging

Coring

Well Testing

Plug & Abandon

DST

Development Well

Production Well

Completions & Workovers

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WELL PLAN

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WELL PLAN

1.1

BASIC GEOLOGY Geology:

The study of the earth’s composition, structure, and history.

Sedimentary Basin:

An extensive depression in the earth’s surface. An estimated 90% of the worlds drilling occurs in offshore and inland basins.

Formation:

1.1.1

Origin of Sedimentary Rock Weathering:

A laterally continuous sequence of sediments that is recognisably distinct and mappable.

Land mass elevated above sea level is weathered and broken down to small fragments. (clastics) Mechanically by water, wind and temperature. Chemically by soluble minerals dissolving into the water.

Transportation:

Rock fragments (sand, silt, and clay) and dissolved chemical compounds (silicates, calcite, iron. etc.) Are transported to the basin by gravity, flowing water, and wind.

Figure 1

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WELL PLAN

Compaction:

The weight of each successive sediment layer (overburden) compacts the sediments below. Compaction squeezes the water out of the sediments and back to the sea.

Cementation:

As the water is squeezed out, the dissolved chemical compounds left behind cements the fragments together to form sedimentary rock.

Shale:

SOFT (Ductile) -

Generally occurs in the shallower depth (<10,000ft) Soft and pliable due to high water content. Fracture and injection pressure approximately same. Pliable texture allows fractures to “heal” quickly. Associated with swabbing, lost circulation, hole washout, and hole pack off.

HARD (Brittle) Sandstone:

Generally occurs in deeper depth (>10,000ft) Hard and brittle due to low water content. Fracture pressure higher than injection pressure. Brittle texture prevents fracture from healing. Associated with hole pack-off/bridge.

UNCONSOLIDATED -

Generally occurs in the shallower depth (<5,000ft) High porosity (25%) High permeability (>2 darcies) Associated with lost circulation, hole washout, hole pack-off.

CONSOLIDATED -

2

Generally occurs in mid to deep depths (>4,000ft) Porosity range (25%-1%) Permeability range (2-10 milidarcies) Associated with differential sticking, underguage hole.

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WELL PLAN

LIMESTONE:

SOFT (Chalk) -

Low compressive strength High porosity (+/- 40%) Permeability range (2 darcies – 10 milidarcies) Will dissolve in fresh water muds. Associated with hole washout, mud contamination.

HARD (Brittle) 1.1.2

Sedimentary Rock Characteristics -

High compressive strength usually fractured. High porosity (20 – 40%), high permeability. Associated with pack-off/bridge, lost circulation, differential sticking. Porosity. The percent of void per 100% volume. Sedimentary rocks (shale, sandstone, and limestone) always exhibit some value of porosity.

Figure 2 - Porosity

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WELL PLAN

-

Permeability (K) The ability of a rock to flow fluids measured in units of Darcies. A rock that is porous does not indicate that it is permeable (i.e. Shale with 10% porosity may exhibit only micro permeability, 10-6 to 10-12 darcy)

Figure 3 - Permeability

1.1.3

Sources of Rock Stress: -

Rock Stress. A force imposed to the rock matrix measured in pounds of force per square inch of area (psi). Natural sources of rock stress originate from overburden stress, tectonic stress and formation fluid pressure. Overburden Stress. The stress produced by the combined weight of the rocks and formation fluids overlaying a depth of interest.

Generated by the force of gravity, the overburden exerts a vertical stress to the formations. A resulting value of horizontal stress is developed depending on rock stiffness (as rock stiffness increases, horizontal stress decreases)

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WELL PLAN

1.2

TECTONIC STRESS · · ·

The stress produced by lateral (side to side) forces in the formation. Tectonic stresses are usually very high in mountainous regions. Tectonic stressed shale generally produces an oval shaped wellbore.

Formation Fluid Pressure:

The pressure of the native fluids(water, oil, gas) within the pore spaces of the rock.

Normal:

Formation pressure equal to a full column (surface to depth of interest) of formation water. Pf (psi) = .465psi/ft x True Vertical Depth ft

Abnormal:

Formation pressure greater than the normal pressure expected for the depth of interest. When permeability drops to near zero, formation fluids become trapped in the pore spaces. Any further compaction of the formation will pressurise the fluids and produce higher than normal formation pressure. Over geological time (millions of years), the high-pressure pore fluid is squeezed out of the shale sections to the adjacent Permeable formations (sandstone, limestone, etc)

Subnormal:

Formation pressure less than the normal pressure expected for the depth of interest. Lower than normal formation pressure may exist in offshore basins due to production depletion, however, naturally occurring subnormal pressure is rare. In inland basins, native subnormal pressure is a common occurrence.

Reservoir Traps:

Source Rock The bed of sediments in which the oil and gas was produced (shale, limestone). Compaction squeezes the oil and gas to the reservoir rock (primary migration). Reservoir Rock The permeable formation which receives and stores the oil and gas volume of primary migration. Reservoir Trap The elevation in reservoir rock to which the oil and gas accumulates (secondary migration) Structural Trap Traps formed as a result of uplifting, folding and/or faulting of the formation layers.

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WELL PLAN

The lightest fluid, gas, rises to the top of the trap. The next heaviest fluid, oil accumulates below the gas and then the water. Fault Trap Traps formed by the displacement of the reservoir rock along a stress crack which positions the face of the down-dip section against impermeable rock. Stratigraphic Trap Traps formed by a permeable reservoir rock grading to a non-permeable rock or the termination of a reservoir rock.

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TYPES OF DRILLING UNITS

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TYPES OF DRILLING UNITS

1.1

TYPES OF RIGS There are many different types of rigs; See Figure 2. Although the basic drilling process is the same, it is the location and depth of the well (and water) which decides which type of rig we will use.

1.1.1

Land Rigs Drilling started on land and these rigs can be very simple in design. A basic hoisting rotating and circulating system is all that is required. Land rigs drilling to great depths through highpressure formations are very different types. In order to accommodate the large Blowout Preventers required for high pressure the rig floor must be a considerable distance from the wellhead. The hoisting system has to be capable of removing the drill string from great depths. The circulating system pumps must be of sufficient pressure rating to effectively clean the bit and remove cuttings from the borehole.

Crown Block

Derrick

Monkey Board Drill Pipe

Land rigs are moved as packages on lorries after the mast of the rig is lowered using the hoisting system of the rig.

Figure 1 - Land Rig Schematic

1.1.2

Swamp Barges A swamp barge is a specialised type of drilling rig used to drill in river delta regions such as Nigeria, Indonesia and the Mississippi area of the USA. A channel is normally dredged before drilling to enable the barge to be towed to location by tug. Once on location the rig is ballasted down on bottom and drilling can commence from the derrick cantilevered at one end of the barge.

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TYPES OF DRILLING UNITS

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Helirigs In remote inaccessible regions such as Papua New Guinea and Brazil, where surface transport is difficult, rigs are transported from site to site by helicopter. These helirigs are land rigs, which can be broken down into convenient packages for transport by helicopter normally 4,000 lbs. or less. Helirigs operations require a great amount of planning from a logistical point of view since the order in which the packages are delivered is vitally important. The packages have to be delivered according to the order of use.

LAND JETTY DRILLING DRILLING

JACK-UP DRILLING RIG

FIXED PLATFORM

SEMISUBMERSIBLE

DRILLSHIP

MUDLINE

Figure 2 - Main Types of Drilling Rig

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TYPES OF DRILLING UNITS

1.1.4

Jack-Up Rigs A Jack-up rig is a self-elevating platform. It is raised by means of a jacking system which operates to lower the legs to the seafloor and raise the rig once the legs make contact with the seafloor. There are two main types of Jack-up rigs: 1.

Mat supported Jack-up e.g.—‘Bethlehem Type’ See Figure 3. This is a Jack-up rig supported by a large steel mat or base, which connects all the legs of the rig. The disadvantage of this type of jack-up is the difficulty often experienced in raising the mat once drilling is completed.

2.

Spud-Can, Jack-up e.g.— ‘Marathon Oil Tournean Type’ See Figure 4. This type of jack-up has typically 3 legs, which are jacked independently. On the base of these legs are (spudcans) which form the supporting structure for the leg and the rig. The advantage of this type of jack-up is that once drilling is complete and the rig is to be jacked down, high pressure water jets in the spud can may be activated to help remove the leg from the soft bottom sediments.

The Jack-up can drill in water depths of approximately 20 to 350 feet depending on their specifications and bottom conditions. Once the support legs have been jacked down and the drilling platform raised to approximately 60 feet above the water, conventional drilling equipment is used to drill the well from the now stable, bottom supported structure. The BOP stack is positioned above the water in the “Texas Deck” area. Most jack-ups employ a mudline suspension system which supports the casing load at the ocean floor and gives a simple mechanical means of releasing the individual casing conductors above the mudline at the conclusion of the well. In general, jack-ups are the most popular type of mobile offshore rig due to their ease of movement and stability. However, weak bottom formations, strong currents where washout may occur, and deep-water can restrict their use. When a jack-up is first moved onto location, it is normal practice to take on additional water ballast to ‘pre-Load’ the leg footings with additional weight. Next the derrick is moved along rails from the centre of the rig to its drilling position cantilevered over the side of the rig—hence the term cantilevered jack-up is often used. Jack-ups are the only type of rig that can be used for workovers on fixed production platforms where there is no longer a platform rig.

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TYPES OF DRILLING UNITS

Figure 3 - Jack-Up On Tow

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TYPES OF DRILLING UNITS

Figure 4 - Independent Leg Jack – Up Rig

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TYPES OF DRILLING UNITS

1.1.5

Drilling Ships These are normally used to drill single expendable exploratory wells. Two basic types are used, the barge type which is towed to location, and the self-propelled ship – shape variety. Drilling ships employing conventional anchor systems usually operate in water depths of 1,500 feet or less. Dynamically positioned vessels, which utilise a computerised thruster system, are capable of drilling in depths of several thousand feet. The BOP stack is located at the mudline and connected to the subsea wellhead housing. If used, the anchoring system usually consists of 8 to 12 anchors on a radially spaced pattern from the bow and stern of the drilling vessel. Some ships connect their anchors to a turret located under the ship, which allows the vessel to rotate 360 degrees and thus achieve a heading into the weather. The required heading is maintained by a series of thrusters. Drill ships have the advantage of relatively economical and rapid mobility between drilling locations, large storage capacity, and deep water drilling capability.

Figure 5 - Drillship Schematic

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TYPES OF DRILLING UNITS

1.1.6

Semi-Submersibles These too are normally used to drill single expendable exploratory wells, although recently a great deal of interest has been shown in using them in conjunction with ocean floor completion systems and some such rigs have already been used in this manner. Some semi-submersibles are towed to location, although many of the more recent vessels are self-propelled. The basic deck configurations are triangular, rectangular, and pentagonal. Anywhere from three to ten or more legs, which are in turn attached to the submerged hulls or pontoons, can support the deck structure. On average these vessels are capable of drilling in water depths ranging anywhere from 200 feet to 1,500 feet. Some semi submersibles also have the capability of drilling while sitting on bottom in the same manner as submersibles, although this is not commonly used. The primary advantage of these vessels over the drilling ships is the high degree of stability in rough water. In comparison to the drill ships, not only is the amount of heave greatly reduced but also the natural roll period is much longer. Dynamically positioned semi-submersibles are not very common in that generally more power is necessary for re-positioning than is required for the ship shape hull. The anchoring system generally consists of a radially spaced pattern of anchors designed to stabilise the vessel for the anticipated wind and sea conditions.

Figure 6 - Semi–Submersible Rig

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TYPES OF DRILLING UNITS

1.1.7

Platform Rigs See Figure 7, Figure 8 and Figure 9. A platform rig is usually an integral part of the production platform and is designed as such. The rig is designed to be moved on a set of hydraulically operated rails between well locations in order to drill a multi-well platform. In the North Sea a platform frequently has two rigs in order to speed the time taken from initial drilling to full production.

1.1.8

Drilling Operations – Personnel Organisation Normally, personnel involved in the drilling operation can be classed into three groups: those on the rig itself, those at the local base, and those at the head office. On the rig site, overall the Oil Company Drilling Supervisor (Rep) carries responsibility for the drilling operations in close liaison with the drilling company Toolpusher. The company representative reports daily to the Drilling Superintendent at the local office. If problems occur, he may report to the local office more frequently. The local office is involved in the day-to-day running and supply of the current operation and planning for the next wells. The Drilling Superintendent will report progress regularly to the Drilling Manager in head office. Major decisions concerning well operations are ultimately made here. This is also where well planning is performed. The Drilling Manager has a variety of services available to him, which give him information upon which to base decisions.

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TYPES OF DRILLING UNITS

Figure 7 - Steel Production Platform

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TYPES OF DRILLING UNITS

Figure 8 - Concrete Production Platform

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TYPES OF DRILLING UNITS

Figure 9 - Tension Leg Platform

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TYPES OF DRILLING UNITS

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THE RIG

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THE RIG

1.1

COMPANY REPRESENTATIVE

Figure 1 - Drilling Personnel Chart

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THE RIG

1.2

CONTRACTOR

TOOLPUSHER

CHIEF MECHANIC

BARGE ENGINEER

DRILLER

MOTORMAN

ASSISTANT DRILLER

ELECTRICIAN

DERRICKMAN

SUPPORT STAFF

ROUGHNECKS

ROUGHNECKS

ROUGHNECKS

Figure 2

1.3

SERVICES Mud Engineer and Loggers Drilling Engineer

Cementers Well Testers

Petroleum Engineer

Wireline Crew

Geologist

Directional Driller Coring Hand Figure 3

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THE RIG

1.4

COMPONENTS OF A DRILLING RIG

1.4.1

Requirements of a Drilling Rig The basic requirement for drilling an oil well, whether it is for exploration, appraisal or production, is always the same. This is true for offshore and onshore situations. Let us examine these requirements. What are we aiming to do? Our aim is to ‘MAKE HOLE’. Hole is made on a rotary rig by applying weight and rotary motion to the bit, and cleaning the resulting cuttings away by the use of a drilling fluid. · · · ·

In order to raise and lower the bit into the hole we require a HOISTING SYSTEM. To turn the bit in the hole we require a ROTARY SYSTEM. To pump the drilling fluid down the hole through the bit and carry cuttings back to surface, we require a CIRCULATING SYSTEM. Finally, to operate the Hoisting System, turn the Rotary System and drive the drilling fluid pump, we require a POWER SYSTEM.

The four systems above have been found on every drilling rig since exploration began; See Figure 7. However, in the demand for greater efficiency, higher safety standards and constant need for economy, has led to the development of the Mudlogging System which is to be found on most land rigs and the majority of offshore rigs. This is basically a computerised data recording system, which constantly monitors each piece of equipment, used in the drilling operations.

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THE RIG

Figure 4 – Drawworks

Figure 5 – Drawworks Control Panel

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THE RIG

Figure 6 – Weight Indicator

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THE RIG

Figure 7 - The Drilling System

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THE RIG

1.4.2

The Hoisting System The hoisting system consists of: · · · · ·

Derrick. Crown Block. Travelling Block. Drawworks. Drilling Line.

The derrick is the steel tower structure, which most people identify as an ‘Oil Rig’.

Figure 8 - Hoisting & Rotary Components

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THE RIG

Figure 9 – The Hoisting System & Crown Block

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THE RIG

Figure 10 – Crown Block

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THE RIG

Figure 11 – Deadline Anchor

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THE RIG

Figure 12 – Crown Saver

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THE RIG

Derrick heights vary from 87 feet on small land rigs to 160 feet on the large semi-submersibles now operating in the North Sea. The height is defined as the distance between the rig floor and the lowest cross member of the crown block assembly. Safe working loads are an important feature of derrick design. Other design considerations include wind load factor, e.g., a derrick on a semi-submersible operating in the North Sea may have to withstand wind speeds of 100 mph (160 km/h) plus, and remain stable. The crown block is fixed at the top of the derrick and with the travelling block acts as a large pulley system to utilise mechanical advantage when hoisting heavy loads. The drawworks is normally situated at rig floor level and is the winch that raises the travelling block via the crown block. The drilling depth capability of a rig is usually based on the drawworks capacity, and the other component's parts of the rig are therefore designed around it. National 1625 DE or Oilwell 3000E Drawworks are capable of handling drillstring weights on holes up to 25,000 feet deep if the necessary power is available. The drilling line is anchored at one end of the drawworks drum and runs up the derrick to the crown block, and is then reaved between the crown and travelling blocks. The other end of the drilling line, known as the deadline, runs down from the crown block to the rig floor where it is anchored on the dead-man or wire line anchor it then runs to spool of spare wire. A weight transducer is employed in the deadline, which is connected to the weight indicator to show the weight of the string. It is important to ensure that the correct weight indicator is employed for the number of sheaves on the travelling block otherwise an erroneous weight reading will be given. A record is kept of the amount of work performed with the line. This is measured in units of Ton-Miles. After a given number of Ton-Miles have been run the wire is slipped and cut, i.e., the anchor is slackened off and fresh wire is slipped into the system from the spare wire spool – a similar length of wire is similar length of wire will be cut off at the drawworks end of the wire. The function of the hoisting system is to raise and lower the drillstem or other tubulars (such as casing, test strings, etc.) into the hole and to support that part of the drillstring weights not being applied directly to the bit to make hole. On many rigs it is difficult for the driller to see how far he has hoisted the travelling block. Furthermore, the drillers’ attention is usually focused on the activity at the rotary table. This makes it very easy for the driller to make a mistake and accidentally run the travelling block into the crown block, which can be dangerous and expensive to repair. To prevent this mishap occurring, a device called the ‘Crown–O–Matic’ is fitted to the drawworks. This device automatically cuts off the drawworks air supply to the hoisting clutch and charges an air piston to lock the brake on, so that no further action can be taken until the ‘Crown–O–Matic’ is reset.

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THE RIG

Figure 13 - Swivel

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THE RIG

Figure 14 – Rotary Table

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THE RIG

Figure 15 – The Rotary Table Operation

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THE RIG

Figure 16 – Kelly Assembly

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THE RIG

1.4.3

The Rotary System The drill string consists of a number of hollow steel pipes known as drill pipe. These are usually about 32 ft long and are screwed together. Screwed to the bottom of the drill pipe, are a number of drill collars, which are of smaller, bore and larger diameter, thus much heavier than drill pipe. The drill bit is screwed to the bottom drill collar. The ‘weight on bit’ is supplied by the drill collars, but it is good drilling practice to ensure that maximum weight on bit does not exceed total drill collar weight so that the drill string is kept in tension, and the risk of failure and associated problems are kept to a minimum. The bit, collars and drill pipe are screwed together and lowered into the hole through the rotary table, which is the source of the rotary motion. As the bit nears bottom, the drill crew will pick up the swivel and Kelly with the travelling block and screw the Kelly to the top most section of the drill pipe. The whole of the assembly from the Kelly down to the bit is known as the drill stem. The Kelly is basically a hollow hexagonal steel bar and is the topmost member of the drill stem. The swivel is permanently attached to the top of the Kelly, and allows the drill stem to rotate whilst suspended in the derrick by the travelling block and it also allows mud to be pumped whilst rotating. Permanently fitted around the Kelly is the Kelly bushing, a snug fitting set of rollers which can move freely up and down the Kelly, but will not rotate unless the Kelly and the rest of the drill stem rotates. From the bottom of this Kelly bushing protrudes four drive pins; as the Kelly and drill stem is lowered through the slowly turning rotary table these drive pins drop into corresponding keyways in the master bushings of the table. Thus rotary motion is transmitted through the Kelly bushing to the drill stem and on to the bit. As soon as the Kelly is torqued up on the topmost drill pipe, the driller starts the mud pumps. With the mud circulating and the bit rotating, the driller lowers the drill stem until the bit touches bottom. Watching the weight indicator carefully, the driller gradually lowers the drill stem until the desired weight is applied to the bit.

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THE RIG

TOP DRIVE The Kelly and rotary table system have been in use since rotary drilling was developed at the beginning of the century. More recently, the top drive drilling system (TDDS) has been developed. This system eliminates the Kelly and rotary table by suspending a large electric or hydraulic motor from the hook. The motor is screwed directly into a 90 ft length of drill pipe and is bored to allow mud to be pumped through it. The advantage of the TDDS is that a connection is only required every 90 ft (instead of every 30 ft with a Kelly) and, if the drill string becomes stuck, the top drive can be used to drill out of the hole. This system has become common in the North Sea from the mid 1980s.

Figure 17 – Top Drive

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THE RIG

1.4.4

The Circulating System See Figure 18 and Figure 20. The main components of the circulating system are: · · · · ·

Drilling fluid, i.e., mud Mud Pits Mud Pumps Swivel Shale shakers.

Drilling fluid or mud is a liquid based on oil or water, which contains various chemicals for different jobs. The purpose of the drilling mud is as follows: · · · · · · ·

Transports the cuttings to the surface Controls formation pressure Lubricates the string and the bit Cools the bit Assists in drilling by jetting action Hold the cutting in suspension when circulation is stopped Deposits a protective ‘Wall cake’ on open hole section.

The mud at surface is stored in large tanks called mud pits. Should the properties of the mud become unsatisfactory, adding various chemicals and clays via mixing hoppers can restore them. Desilters and desanders can remove excess sand and silt, which quickly erode the highpressure parts of the system. Mud is circulated using mud pumps. The mud pumps are charged from the active mud pit sometimes by gravity, but more frequently nowadays by low-pressure centrifugal pumps. The mud is pumped through a series of high-pressure lines, up the standpipe and into the Kelly hose. In most systems these surface lines will be tested to 5,000 psi. The flexibility of the Kelly hose allows the high-pressure fluid to pass from the rigid standpipe to the rotary swivel which is lowered along with the rest of the drillstem as drilling progresses. The rotary swivel is apiece of equipment used for supporting the weight of the string whilst allowing it to rotate, it also permits the drilling fluid to enter the drill stem from the Kelly hose without loss of pressure, thus it must be strong and durable. The drilling fluid is pumped down the centre of the drill stem and through the bit nozzles where it picks up the cuttings, the resulting mixture of mud and cuttings returns to the surface via the annular space between the hole and the drill stem. The mud must next be treated; See Figure 20. On reaching the surface the mud is passed over the shale shakers: vibrating wire screens, which segregate most of the cuttings from the drilling fluid. After passing through the shale shakers, the mud passes through a sand trap, which is a large tank in which further cutting can settle out before the mud is returned to the active pit for reuse. The mud may be treated in the active pit as it is circulated to replace the chemicals used on the cuttings. Further mud treatment may also be carried out using desanders and mud cleaners. ã DTL 2001 – Rev 2

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Figure 18 - The Mud Circulation System

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Figure 19 – Mud Pump System

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THE RIG

Figure 20 - Mud Treating Equipment

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Figure 21 – Mud Pumps

Figure 22 – Shale Shakers ã DTL 2001 – Rev 2

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Figure 23 - Desilter

Figure 24 - Desander

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1.4.5

The Power System On most land rigs and some of the older offshore drilling installations, power to the hoisting, rotary, and circulating systems is supplied direct from diesel engines through a compound of heavy gearing, chains, sometimes ‘V’ belts and torque converters. However, on the more up-to-date rigs and all new production platforms, diesel-electric generators supply a central power source for all the systems; using a system of thyristers or silicon controlled rectifiers (or SCRs) alternating current (AC) is converted to direct current (DC) and fed dc to electric motors which act as individual driving forces for the various systems. Also common are diesel-hydraulic rigs in which power from diesel engine is converted to oil pressure by means of a pump. The pressure is then used to drive hydraulic motors and provide drive.

1.4.6

Mud-Logging System The mud-logging unit consists of a mobile air-tight laboratory, in which is housed a computer and data recording system along with equipment for analysing cuttings and fluid returned from the wellbore. The operator rents these units from a mudlogging company. The unit is manned 24 hours a day by a mudlogger whose job it is to ensure that cuttings samples are collected and labelled during drilling and to monitor the multitude of information which the unit produces. If there is any gas coming from the well, or if there is a pit gain or increase in flow, the logger will immediately notify the driller of a possible well ‘kick’. A ‘kick’ is explained in more detail in the well planning and well control sections of this manual. This is a very important function of the mudlogging unit. Furthermore the unit analyses all information pertaining to the drilling operation (e.g. RPM, Weight on Bit, Hook Load, Temperature of Drilling Fluid.) In order to allow determination of the most efficient drilling parameters. The Mudlogging Company would usually install additional computer displays in the oil company representative’s office and the Toolpusher office with the information being constantly updated as the well progresses.

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1.5

GEOLOGICAL INFORMATION OBTAINED

1.5.1

Aims The information acquired by the geologist during the drilling of an exploration well allows him to do three things. Firstly, he can detect minute amounts of hydrocarbons in the rock samples. Secondly, he can evaluate whether these traces indicate that the well has encountered a commercial oil field. Thirdly, he can build up the sequence of rock types that will enable him to establish whether or not there are suitable hydrocarbon source rocks, reservoir rocks and cap rocks in the area in which the well has been drilled.

1.5.2

Sources of Information The geologist makes his deductions from two different types of information. He looks at rock samples derived from the well. He looks indirectly at the rocks from the rate of penetration, i.e., their ‘drillability’, and also from effects that different rocks have on a series of logging detectors that are lowered into the wellbore from time to time. Rocks are collected from the wellbore by three different means. Cuttings are circulated out in the mud system, sieved off, washed and examined. Larger samples are occasionally needed. These are taken by cutting cores, either using a core–bit, sampling the bottom of the hole, or a wire line sampler, sampling the side of the wellbore. Cuttings samples are the most common form of rock examined by the geologist. However, these samples do suffer from some limitations. Different bits cut different sizes of rock chips from the bottom of the hole. Diamond bits tend to grind off cuttings rather than chisel them off as a tooth bit does. The grinding action of a diamond bits tend to disaggregate the rock into component grains making some samples difficult to interpret. Cuttings samples are to some degree contaminated by rocks falling down from already drilled sections of the hole. This contamination is known as caving and is generally associated with fine grained fissile rock types which form much less stable wellbore walls than permeable massive rocks such as sandstone and limestone’s. The effect of this caving is minimised by sieving out the large fragments of rock in the samples. When diamond bits or short tooth bits are being used, samples from the desander may be examined. In order to cover the deficiencies of cutting samples, sidewall cores may be taken. These are obtained by firing a small cylindrical bullet into the side of the wellbore. The samples are no more than an inch and half long and three-quarters of an inch in diameter but can be shot after petrophysical logs have been run. Thus, as well as obtaining uncontaminated samples, we can, in this manner, obtain samples opposite petrophysical log anomalies.

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Full-hole cores are taken in order to obtain the largest possible sample from the wellbore. They are taken in runs of up to 30m and they are from 3" to 5" in diameter. These large samples permit the geologist to reconstruct the sedimentary environment in which the rocks were laid down and so obtain the best possible lithological and palaeontological control. This is used to extrapolate from the single wellbore evidence for the distribution of reservoirs in the field. Full-hole coring is normally only justified in examining the geology of oil field reservoirs or potential oil field reservoirs. The elimination of doubtful exploration reservoir targets amply justifies the expense of obtaining samples of such reservoirs by coring. The samples can and are frequently used for quantitative evaluation of fluid flow characteristics of reservoirs for petroleum engineering purposes. This data may save the cost of production testing which is especially high in offshore areas. Rate of penetration logging has for many years been a well-established technique for determining the gross lithology of the rocks by their drillability. Reservoir rocks generally drill faster than cap rocks so that the presence of the reservoir can be determined before there has been time for samples of it in the cuttings to arrive at the surface. The variations of drillability of some rocks may provide characteristic markers that can be correlated from well to well and enables the geologist to adjust his forecast as the well is drilled. Recently, we have been attempting to normalise this rate of penetration to allow for the effects of differing bit weights, bit types, rotation speeds and mud hydraulic factors. This normalised rate of penetration can be turned into a pore pressure estimate. Knowledge of pore pressure is useful in programming drilling fluid weights and giving advanced warning of zones where shales may give drilling problems; See Section – Well Planning. At intervals during the well, petrophysical logs are run by lowering a detector down the well on the end of a multi-core armoured electrical cable. Usually this procedure is done four times during the course of a well: three times prior to running casing and on the fourth occasion at total depth prior to terminating the well. A number of physical properties of the rock are measured such as electrical resistivity, velocity of sound in the rock, and natural and induced radioactivity. From these measurements, the porosity and permeability of the rock can be estimated. Lithology of the rock may be determined and a curve of variation of the appropriate parameter with depth is obtained. Taken in conjunction with the descriptive evidence of the rock samples, this indirect evidence allows the geologist to construct the best possible interpretation of the geological sequence encountered by the well. In zones of possible reservoirs, logs can be interpreted to give quantitative estimates of hydrocarbon reserves and well fluid yield characteristics. Well logs are the basis of most correlation and correlation is the key to the exploration of well data over the basin.

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1.5.3

Applying Well Data to Further Exploration After the well has been drilled, the geologist work is not done. He has to put together from numerous sources concise factual reports of the data obtained by the drilling of the well. This essential sifting process is a vital prelude to any evaluation of the well results. There follows the refinement of the geological model for the area and consequent changes in the exploration programme for the area. The first task is to produce quickly a completion report, which is essentially an annotated discussion of the sequence encountered by the well. This data is also put on computer for building up a bank of well data. Trade Journals and scouting sheets provide basic data on other wells that are drilled following which the company decides to exchange well data on a well for well basis for the most interesting wells drilled by the competition. Not always do companies agree amongst themselves what wells need to be drilled but a company with a large exploration programme of its own can usually obtain the necessary well data points for setting up its geological basin model. The next stage is to evaluate the results from the well to decide whether a second well needs to be drilled on the same structure, to decide whether adjacent structures are worth testing by drilling, and to see if it would be worth while taking a financial interest in other people’s exploration programmes. Finally, and most important, it has to be decided for what adjacent acreage it is worth applying. This process of evaluation and review is continuous. The data from each well is fed in as soon as it is drilled or obtained by exchange. The basic tools for this review are the structural contour map on the top of the reservoir from which exploration targets can be localised and a series of other maps showing the distribution of cap rocks above the reservoirs, reservoir rocks and source rocks. Nowadays, in considering the distribution of source rocks, we have to consider whether or not they have been buried below the threshold of hydrocarbon generation. This threshold is determined by organic geochemical analysis of samples from a few widely spaced wells drilled early in the exploration programme. In summary we can see that the well provides a great deal of factual data which affects the exploration of the basin even though the well itself may encounter no commercial hydrocarbon deposits.

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DRILLING ASSEMBLIES

1.1

BOTTOM HOLE ASSEMBLIES (BHA) The bottom hole assembly (BHA) controls the direction and penetration rate of the bit. There are many variations of BHA which will be discussed in more detail in the directional drilling section of this manual. However, the three main components of a BHA above the bit are drill collars, stabilisers and heavy weight drill pipe.

1.1.1

Drill Collars – See Figure 4 A drill collar is a thick walled pipe, threaded on both ends (box up-pin down). The normal length of a drill collar is abort 30 ft. Drill collars are used primary weight-on-bit. For bits drilling in hard formations, high weight on bit is required and thus more drill collars are required. For softer formations, less weight and thus less drill collars are required. There are a variety of specialised drill collars such as ‘pony’ collars which are short (perhaps 10 ft) and non-magnetic drill collars whose function is explained in the following sections of this manual. Common drill collar sizes are 4¾”, 6½” and 8”.

1.1.2

Stabilisers – See Figure 2 As the name suggests, stabilisers are used to provide stability to the drill collars. They are usually the same diameter as the bit and therefore hold the BHA central in the hole. Again, there are specialist stabilisers such as non-magnetic, which are used for surveying and undergauge which are used in directional work. These functions are described in the subsequent sections on this manual. Common stabiliser sizes 8½”, 12¼” and 17½”.

1.1.3

Heavy Weight Drill Pipe – See Figure 6 Heavy weight drill pipe is used as a transition between the heavy, stiff drill collars and the more flexible drill pipe. It is thick-walled and has hard banding on the tool joints and in the middle of each joint to provide wear resistance. Heavy weight drill pipe can be used to provide extra weight to the drill bit, but this is not a common practice. Common sizes of heavy weight drill pipe are 5” and 3½”.

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1.2

DRILLING ASSEMBLIES All holes are deviated to some extent, they tend to spiral to the right, there is no such thing as a ‘straight hole’. However, operations attempt to keep deviation within certain small tolerances, to allow the target to be reached. If deviations are not controlled, the target can be missed which defeats the object of the drilling well.

1.2.1

Vertical Holes As far as exploration and appraisal on land are concerned, vertical holes are commonly called for. Deviation per 1,000 ft is usually specified in the well plan, this figure being allowed to increase as the target depth is approached. The deeper the formation, the harder the rock is likely to be, so for optimum penetration heavier weights on bit must be utilised however, this can increase the tendency to deviate. To prevent excess deviation, the operator will pay special attention to the make-up of the bottom hole assembly (BHA). There are two factors which can affect hole deviation, they are: formation dip, and the bending characteristics of the bottom hole assembly. The effect of formation dip is only serious where the structures are hard, at high angle and of different composition from layer to layer. Where these conditions are present, the bit will tend to drill ‘up dip’. When planning a well, consideration is given to the ‘angle of dip’, this information being obtained from offset wells and seismic surveys. The surface location will be situated ‘down dip’ of the reservoir so that the hole will tend to ‘drift’ into the target area. The bending characteristics of the bottom hole assembly are always present and obviously have the biggest affect on the ‘straightness’ of the hole; See Figure 1. Bending characteristics are affected by, weight on bit, drill collar diameter and the position and number of stabilisers in the BHA. If drill collars were the same size as the hole, no deviation problem would occur. We have to get as near as possible to this situation, without affecting the annular velocity too drastically. Relatively large diameter collars for hole size and stabilisers are used to reduce bending characteristics or ‘stiffen up the bottom hole assembly; See Figure 2. A ‘stiff BHA’ will keep a hole on course, but if it is already deviated this stiffness will not bring it back to the vertical; See Figure 7. To do this we do not use a stiff BHA but rely on gravity or the ‘pendulum force’ on the string. To obtain a good ‘pendulum effect’ the point of contact of the drill collars with the hole wall must be as high as possible, if there is too much weight on the bit this height will be drastically reduced, but by placing a stabiliser at a strategic point above the bit a certain amount of weight can be applied before the point of contact gets low enough to negate the pendulum forces; See Figure 8. These restoring force are minimised when a stabiliser is placed directly above the bit as it will tend to build hole angle; See Figure 9.

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‘Packed Hole’ Assembly

‘Pendulum’ Assembly

STABILISERS

Possible Keyseats

Drill Collars

Drill Pipe

‘Crooked Hole’ Assembly

Figure 1 – Main Types of Bottom Hole Assembly

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Figure 2 – Stabilisers

Figure 3 – Rockyback Stabiliser

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Figure 4 – Drill Collars

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Figure 5 – Cross Over

Figure 6 – Heavy Walled Drill Pipe

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String Type Stabilizer

String Type Stabilizer (1/4’’ Gauge Wear Max.) 30’’ Drill Collar

Non Magnetic Drill Collar String Type Stabiliser

Near Bit Stabilizer ( 1/8’’ Gauge Wear Max.) Bit

Short Drill Collar

Straight Hole Drilling

Maintaining Hole Angle Near Bit Stabilizer Bit

String Type Stabilizer

Non Magnetic Drill Collar Drill Collar

Hole Angle Decreases Hole Angle Increases

Non Magnetic Drill Collar Near Bit Under gauge Stabilizer ( 1/2’’ to 1’’)

Near Bit Stabilizer ( 1/8’’ Gauge Wear Max.)

Increasing Hole Angle

Decreasing Hole Angle

Figure 7 – Assemblies

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Although reducing bit weight tends to fetch the hole back to vertical, a sudden reduction can cause a ‘dog leg’ which in turn can lead to a ‘key seat’, this can cause the drill stem to become seriously stuck in the hole; See Figure 8. To sum up; to keep deviation to a minimum the correct balance of weight on bit and stabiliser placement must be used. Once the hole’s course is set, a stiff BHA is the most effective method of keeping that course set, but the stiff BHA will not straighten a hole. To check hole deviation some sort of instrument is required, a number of instruments have been developed ranging from a simple ‘Totco survey tool’ to the more sophisticated ‘gyroscopic multiple shot’ survey. Most commonly used is the Totco Double Recorder, a mechanical device which consists of a pendulum with a needle point, a clock mechanism and small circular disc. After a pre-set period the disc moves rapidly upwards and a chart on the disc is perforated. After about a 30 seconds interval, the disc revolves 180o and the perforating process is repeated. On recovery, the chart can easily be read, if the two angles are vastly different the survey is considered a misrun. This type of instrument will measure deviations between 0o and 16o. However, this instrument only records hole inclination and is now being replaced by the more sophisticated magnetic single shot. This tool measures hole inclination and azimuth (or heading) and is used to give a more accurate picture of the well. However, to operate the tool effectively requires the use of non-magnetic drill collars (usually 2) and a non-magnetic stabiliser to remove the magnetic effect of steel upon the survey.

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Wellbore

Drill Pipe

Keyseat Lateral Force

Dogleg Angle

Figure 8 – Keyseat Formation due to Dogleg Angle

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DRILLING ASSEMBLIES

1.2.2

Directional Holes Controlled directional drilling means causing the wellbore to deviate along a predetermined route. Deviation wells may be necessary in the following situations; See Figure 9. · · · · · ·

When local conditions dictate that the rig cannot be sited directly above the target. When it is impossible to drill ahead because of a fish in the hole, and too expensive to respud, the well is ‘side-tracked’. When drilling through a fault plane would create a risk of the formation slipping thereby shearing casing or otherwise causing damage. When deviation around a salt dome to eliminate expensive mud and hole problems. When drilling from a production site to allow several wells to tap a field from one location. When drilling a relief well to control a blowout.

Deviated holes fall into one of three basic hole patterns; See Figure 10. The choice of a particular pattern to fit a given drilling programme is not simple. It involves many complex factors such as the knowledge available about the geological structures, mud and casing programme, spacing of targets, and so on. In the Type I or slant pattern, the initial deflection angle is obtained at relatively shallow depth, and from that point on the angle is maintained as straight as possible to the target. Once the angle and direction are obtained, surface casing is set through the deviated section and cemented. Generally, the Type I pattern can be employed in two distinct depth programmes. It can be used for moderate depth drilling in areas where intermediate casing is not required and where the oil-bearing rock is a single zone. It can also be used for deeper wells requiring a large lateral displacement. In these deep wells, an intermediate casing string is set through the curved section to the required depth. The initial angle and direction are then maintained below the casing to total depth, using a hold assembly; See Figure 7 and Figure 11. The Type II or ‘S’ pattern is also deflected near the surface. After the deflection is accomplished, surface casing is set and cemented. Drilling continues along this deflected course until the desired lateral displacement is reached; then the hole is returned toward vertical and an intermediate string of casing is set. Drilling is resumed in the vertical hole, and the hole remains vertical until total depth is reached. This pattern is employed on deep wells in areas where gas troubles, salt water flow, and so on dictate the setting of intermediate casing. It also permits a more accurate bottom-hole spacing in multiple pay zones.

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Figure 9 – Deviated Wells

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Deflection in the Type III or ‘J’ pattern is started well below the surface. The hole angle is then maintained to the target point. Deflection angles are relatively high, and the lateral distance from vertical to the desired target is usually shorter than in other patterns. With recent increases in technology and the need for greater economy, the deviated portions of some wells have been drilled horizontally through the reservoir zones. This allows a far greater area of reservoir to be exposed to the well and can usually increase production potential as much as 6 fold. To ‘kick off’ a well from vertical, a downhole motor and ‘bent sub’ are usually used. The bent sub is a short tube with perhaps a 2 degree bend in it. The motor is placed below the bent sub and is driven by mud being pumped through it. Kick off in the desired direction is basically achieved by pointing the motor/bent sub assembly and then switching on the mud pumps to turn the motor. The drill string is not rotated during kick off. Once kick off has been achieved and angle has built to perhaps 10 degrees, the bent sub and motor are removed and a rotary build assembly is used. To build hole angle, a stabiliser is placed near the bit; See Figure 9, this acts as a fulcrum when weight is applied and tends to lift the bit. To decrease hole angle the pendulum principle is used, and to maintain hole direction, the stiff bottom hole assembly is utilised. A ‘monel’ or non-magnetic drill collar is installed near the bit to enable directional surveys to be more accurately made. Directional drilling causes ‘dog legs’ or bore hole deviations, if these ‘dog legs’ are too severe the following problems can arise: · · · ·

Difficulty in lowering logging and survey instruments below the bend. Casing separation at the coupling due to excessive flexing. Stuck or collapsed casing. Inferior cement jobs caused by non-centralised casing.

A ‘dog leg’ which is in excess of 5o per 100 ft will probably cause trouble, the deeper the hole goes the more troublesome this area will be, especially if a key seat forms. Directional drilling and surveying directional wells are specialist jobs, therefore, the operator will usually call in specialist companies rather than rely on the drilling contractor, whenever there is directional work to do.

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TYPE 1 SLANT WELL

Initial Build at Shallow Depth

TYPE 2 ‘S’ WELL Initial Build at Shallow Depth

Long Radius

Hold Section

Long Hold Section Drop Section to Return to Vertical Final Hold Section

TYPE 3 ‘J’ WELL Long Vertical Section

Build Near to Target Depth Short Radius

Final Hold Section (May Be Horizontal)

Figure 10 – Types of Deviated Wells

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String Type Stabiliser

String Type Stabiliser

Non-Magnetic Drill Collar

Near-Bit Stabiliser Bit Figure 11 – Maintaining Hole Angle

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1.3

A GLOSSARY OF THE MORE COMMON DOWN HOLE TOOLS Bottom Hole Assembly BHA, the hook-up of drill collars and tools between the drill pipe and the bit. Core Barrel A device for cutting and retrieving a solid cylindrical core from the formation. Deflection Tools Specialist equipment installed on the bottom of the drill stem to change the hole angle. They include: · · · · ·

Whipstock. Knuckle joint. Deflection bit. Position displacement motor (or PDM). Turbine motor.

Drill Collars Heavy tubulars which supply the ‘weight on bit’: ‘Slick’: ‘Spiral’: ‘Square’: ‘Zipped’: ‘Monel’:

Smooth outside diameter. Grooves machined in a spiral on the outside diameter to minimise the chances of differential sticking. Square cross sectional profile for extra stiffness. Grooved at box end to facilitate use of DC elevators and slips. Non-magnetic DC of nickel/copper alloy for surveys are required.

Drilling Jars A tool placed in the bottom hole assembly which jars or shocks loads the drill stem, should it become stuck. Some jars double as shock subs. Jar Accelerator: A tool used in conjunction with the jar to intensify the shock and then dampen the rebound. Drill Pipe The tubulars which join the Kelly to the BHA, API specifies the drill pipe and tool joints as ‘ drill string’ and the total assembly from swivel to bit as ‘drill stem’. Heviwate/Flexwate/Hevywall: Brand names for DP with smaller internal diameter used between DC and DP. Key Seat Wiper Run at the top of the collars to open out suspected key seats, it is effectively a jar with gauge blades on it.

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Roller Reamer A tool which has small rollers at the points of contact with the hole wall to: · · · ·

Maintain hole size behind the bit in stiff BHAs. To act as a fulcrum to increase hole angle. To act as a stabiliser in a stiff BHA. To act as a key seat wiper.

The small rollers are interchangeable, different cutters for different formation types are available, ranging from smooth for maximum support to tungsten carbide insert type for long life in hard formations. Under Reamers Does the same job as a hole opener in that it follows a bit and enlarges the hole. However, in some situations the hole size is greater than the ID of a previously set conduit, be it casing, well head or riser, thus the under reamer, which opens to full size on application of pump pressure. Stabilisers The applications of the stabiliser have been discussed in other parts of the manual. Common stabiliser patterns are: · ·

A ribbed sleeve mounted on a mandrel. The mandrel rotates and the sleeve stays almost stationary. The solid blade type stabiliser, the blades can be welded or bolted, straight or spiral.

Subs Bumper sub – incorporates a ‘trombone’ joint for drilling without a compensator or for landing tools on a floating vessel. Inside BOP sub – a non-return valve which can be run in the string for blowout control. Other BOP subs include the dart sub, the Kelly cock sub and the float sub. Crossover or X/O sub – for joining tubulars with different threads together. Junk sub – ordinary ‘boot’ type for cleaning junk from the hole, often run prior to a diamond bit run. Kelly Saver sub – to save excessive wear on the pin end of the Kelly, sometimes termed ‘throw away sub’. Lifting sub – If collars are not ‘zipped’ this must be screwed into the C/C in order to lift it with the elevators. Shock sub – run near the bit to save wear and tear on the drill stem and prolong bit life.

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1.4

DRILLING BITS

1.4.1

General Drilling bits, in the context of modern drilling are all rotary bits and a number of individual rotary bit designs and are available from a variety of manufacturers. All are designed to give optimum performance in various formation types according to the ideas and experience of each company. The three main types of bits used today are: · · ·

1.4.2

Rolling cutter (roller) bits. Polycrystalline Diamond Compact (PDC) bits. Diamond bits.

Rolling Cutter Bits See Figure 12 and Figure 13; The first successful rolling cutter bit was designed by Howard Hughes in 1909. Up to this time hard formations had only been drilled with cable tool rigs but the introduction of the rollers with teeth enabled hard formations to be drilled with rotary rigs. Roller bits have teeth of varying length and spacing on three cones, the spacing and length of the teeth depending upon the formation to be drilled. The design of the cone is to obtain the maximum cutting rate without balling (causing the teeth to be clogged with cut formation). In addition to the different number, spacing, pattern and length of the teeth in different types of bits, the cones are also offset; See Figure 14, i.e. the cone axes do not intersect at a common point. This offset imparts a drag action to the teeth as the bit is rotated. Bits designed for soft formations have long widely spaced teeth with the maximum of offset and for progressively harder formations the number of teeth increases, the length shortens and the amount of offset decreases until for very hard formations bits there is no offset. The teeth in the cone are either milled, i.e. cut out of the cone itself and hard faced, or consist of tungsten carbide inserts or buttons in place of the milled teeth. A standard format has been developed by the IADC for classifying rockbits according to manufacturer, bearing type, formation and tooth type; See Figure 14. A modern improvement upon the standard roller bit is the jet bit in which the water ways in the old standard bit have been replaced with interchangeable nozzles. Each nozzle directs a high velocity steam of drilling fluid directly on to the bottom of the hole which rapidly removes the cuttings. This allows each bit tooth to strike new formations rather than expend some of its energy in regrinding loose cuttings. The pressure losses through these nozzles are considerable and require both extra pump capacity and pump horsepower, but these are considered worthwhile for the increase in ROP which are achieved with jet bits.

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Figure 12 – Carbide Tooth Bit

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Figure 13 – Steel Tooth Bit

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Figure 14 – Rock Bit Offset

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There are three types of bearings used on roller or rock bits: 1.

Non sealed bearings.

2.

Sealed bearings.

3.

Journal bearings.

The non sealed bearing consists of a roller race which is greased during the assembly process or in some cases after assembly. In the case of large bits for top hole drilling which can be reused it is often possible to grease the bit after use so that the bearing will not deteriorate during storage. In addition to the roller bearing, ball bearings are also used, the whole bearing assembly size being determined by the thickness of cone shell and journal size to give maximum life. A development of the non sealed bearing is the sealed bearing which is a combination of roller and friction bearing, or a ball and roller bearing. In the sealed bearing a reservoir of lubricant is built into the bit body and as the bit is used the differential pressure across the bit forces the lubricant into the bearing. The journal bearing was developed for use with the insert bits to give longer bearing life and consists of friction bearing and a ball race. This bearing again is lubricated under pressure to give maximum bearing life. The main differences in the construction of the journal bearing bit are: · · 1.4.3

Larger leg journal diameters. Thicker cutting structures or cone shells.

Diamond Bits See Figure 15 and Figure 16; These drill by a scraping action of the industrial diamonds which protrude from a metal matrix. Their use can be mainly justified by the long life of a bit which eliminates the need for tripping and consequently increase in on bottom time. The cost of the diamond bit is high, but is offset by the salvage valve of the bit which may be as high as 75% of initial cost. Diamond bits are most widely used as core heads. A core head is usually a diamond bit which has a cut out in the centre which allows a core or spine of rock to be left when the hole is cut. The core is recovered by a core barrel.

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DRILLING ASSEMBLIES

Figure 15 – Natural Diamond Bit

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Figure 16 – Polycrystalline Diamond Compact Bit

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Figure 17 – Core Bit & Barrel

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DRILLING ASSEMBLIES

1.4.4

Bit Performance The bit performance evaluation is a complicated procedure as there are so many variables involved, and the basic requirement of any drilling is to achieve the lowest cost per foot drilled. Some of the factors that are involved are: Personnel Efficiency Experience Special Training Company Employee Relations Pride in Job Chance for Advancement Rig Efficiency State of Rig and Preventative Maintenance Correct Size Ease of Operation Degree of Automatically Power Equipment Formation Characteristics Compressive Strength Hardness/and/or Abrasiveness State of Underground Stress Elasticity – Brittle or Plastic Stickiness or Balling Tendency Permeability Fluid Content and Interstitial Pressure Porosity Temperature Mechanical Factors Weight on bit Rotating Speed Bit Type Mud Properties Density Solids Content Flow Properties Fluid Loss Oil Content Surface Tension

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Hydraulic Factors Jet Size Pump Capacity and Horsepower Even assuming that the first two groups are not deficient there are sufficient factors that will make the selection of the correct bit a real problem, and in the case of a wild cat well only rough estimates can be made of the type of bit is used. However, experience and examination of the bit will help to improve the choice, and in a development situation all data should be recorded, and from that data better bit selection is possible.

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DRILLING FLUID

1.1

WHAT A MUD MUST DO Whatever we are doing there are approximately ten functions, which a mud must perform. This is true regardless of which hole section we are drilling, although the emphasis changes in different hole sections. A mud must: 1.

Control formation pressure

2.

Prevent caving of the formation

3.

Cake off permeable formations

4.

Clean cuttings from hole

5.

Suspend cutting when circulation stops

6.

Release cuttings at surface

7.

Cool and lubricate the bit and drillstring

8.

Minimise formation damage

9.

Allow easy formation evaluation

10.

Minimise corrosion of the drill string

OF course the mud also does other things. For example, it transfers hydraulic horsepower downhole to the bit, but this does not really affect the way in which we run the mud.

1.2

FUNCTIONS AND MUD PROPERTIES To perform the functions listed above, a mud must possess certain properties. There are as follows:

1.2.1

Control Formation Pressure This is done by mud density (normally called mud weight). The mud weight can be increased in 2 ways: a) b)

By dissolving salts in the mud. By increasing the solids content.

If extra solids are added to raise the mud weight, then the mud must have some viscosity to stop these solids from settling. Enough mud weight is needed to hold back any oil water or gas in the formation. However, too much mud weigh may break down the formation and cause lost circulation or stuck pipe.

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1.2.2

Preventing Caving We want the hole we have drilled to be as close to the gauge as possible. This makes the hole easier to log, helps to ensure that the casing is properly cemented in place, and minimises mud costs. If the hole collapses during drilling, there is a danger of the pipe becoming stuck. Too low a mud weight may allow the walls of the hole to fall in. the hydrostatic pressure from the mud should normally match or exceed the formation pressure. Mud chemistry is also important. Reactions between the mud and the formation may cause the formation to swell. The extra pressure from the formation swelling may cause caving. Where we are drilling a formation which can dissolve (e.g. salt), we have to treat the mud to stop this from happening. Otherwise large caverns will be formed where the formation has been dissolved away.

1.2.3

Caking Off Permeable Formations Permeable formations are those where the pore spaces are interconnected, allowing fluid to and from the wellbore. To cake off these formations, the mud requires particular filtration properties. As the mud passes into the formation, the solids in the left behind, forming a filter cake. This keeps the hole in a stable condition. It also cuts down the quantities of mud and filtrate entering the formation.

1.2.4

Cleaning Cutting from the Hole How easily cutting are removed from the hole depends on the size and weight of the cuttings. It also depends on the flowrate, or more accurately on the annular velocity. In term of properties, cuttings removal depends on the viscosity of the mud. Muds with higher viscosities clean the hole better. The mud weight also plays a part. With higher mud weights, the buoyancy factor is greater. The cuttings have fewer tendencies to fall back down the hole, and are more easily carried to surface.

1.2.5

Suspending Cuttings To suspend cutting when circulation stops, the mud must have a gel structure. Gels are not the same viscosity. They are a property of the static mud. Viscosity is a property of the mud when it is moving. Too strong a gel structure can cause problems with breaking circulation and with swabbing on trips. Mud weight is also a factor: at higher mud weight, there is more buoyancy and the cuttings are closer to floating.

1.2.6

Releasing Cuttings When mud is circulated out of the hole, we need to separate the cuttings from the mud. This is normally done by the solids removal equipment, or by settling. All types of solids removal equipment work best with low viscosity and gel strengths. High gel strengths also make it difficult to settle the cuttings. Mud chemistry is also important; if the mud reacts with the cuttings, then they tend to become smaller and more difficult to remove.

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1.2.7

Cooling and Lubrication The drillstring and the bit both generate heat through friction. Thus the lubricity of the mud is important. Better lubrication leads to less friction heat being developed. Cooling depends on the thermal conductivity of the mud. The mud carries heat away from the bit and drillstring. The mud cools as it passes through the pit system. Offshore, extra cooling occurs as the mud rises from seabed to the rig. Thus other factors such as pit layout and water depth come into play.

1.2.8

Formation Damage With permeable formations, the liquid part of the mud (filtrate) can flow into the formation. The solids are left behind as a filter cake. Formation damage depends mainly on the filtration properties of the mud. The filter cake can permanently affect the permeability of producing formations. The filtrate entering the formation can also cause damage. Reaction between filtrate and formation can make this damage worse. Thus the mud chemistry is important.

1.2.9

Formation Evaluation Formation are evaluated in three different ways: 1. 2. 3.

From the cuttings From electric logs By coring.

The cuttings are collected and checked by the mud loggers and the geologist. The condition of these cuttings depends mainly on the mud chemistry. The information gained from logs and cores depends on the filtration properties of the mud. Thick filter cake can make logging difficult. Filtrate invasion can give misleading results for both logs and cores. 1.2.10

Corrosion In water based muds, corrosion is controlled by the mud chemistry. With oil muds, corrosion problems are much reduced.

1.3

COMPOSITION OF MUDS Muds consist of a mixture of liquids, solids and in some cases, gases. We normally refer to these as the liquid phase, solids phase, etc. in most muds at least two phases are present. Where we have two liquids which do not mix (e.g. oil and water), we talk about having two liquid phases one liquid is emulsified in the other (e.g. in oil based mud, water is emulsified in the oil). We then distinguish between the liquid phases by calling one the continuous phase (in OBM this is the oil). The other, we call the discontinuous of internal phase, because this is present only as emulsified drops.

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1.4

WATER MUDS AND OIL MUDS Water is cheap and readily available. However, it is very good at dissolving things, and allows reactions to take place quickly. Maintenance is directed at making the water a less effective solvent, and at slowing down the reactions that may occur. Oils by contrast are not very reactive. However, they are expensive and they are pollutants. Maintenance is directed at reducing waste. This is both for cost and for environmental reasons.

1.5

CLAYS Clay chemistry is extremely important in mud technology, especially when considering water based mud system. In virtually every well drilled, shale sections are encountered. Shales all contain clays. The variations between shales are largely caused by the proportion of the various clays present. Clays in the formation can cause three main problems: 1. 2. 3.

Cutting can easily be incorporated into the mud system forming colloidal particles. These cannot easily be removed and can seriously alter the mud properties. Interactions between the mud and exposed shale formations can cause unstable hole. Mud filtrate can react with clays present in producing formations to cause permanent formation damage.

1.6

WATER-BASED MUDS

1.6.1

Introduction There many different additives for water-based muds, and a number of different systems. However, the choice of products and systems is very simple provided that we remember the basic mud chemistry. The first stage is to decide what water chemistry to use. To do this, we must consider: a) b)

The formation to be drilled (e.g. if salt is to be drilled, salt saturated water must be used). The available water supply.

Most viscosifiers, water loss control additives, etc will only work under specific conditions. Thus once water chemistry has been decided, we are limited in our choice of product. We should only use those that will work well in the water chosen. The mixing procedure is then very simple. 1. 2. 3. 4. 5.

4

Test water and treat to correct chemistry Add viscosifier Add water loss control Adjust other properties as necessary Weight up to required mud weight.

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1.7

OIL-BASED MUDS

1.7.1

Introduction Nearly all contamination problems with water based muds relate to the water itself. Most contaminants are water-soluble. In theory, by using a liquid phase other than water. We should achieve a more stable mud. Historically, oil muds were formulated using either diesel oil or crude oil as the liquid phase. Both these products were available in sufficiently large quantities. Diesel had the obvious advantage of being more consistent in composition. Crude oil muds are now rare. Pollution problems are far greater with oil muds than water based muds. As a partial solution, a series of de-aromatised oils have been introduced. These are approximately the same fraction as diesel, but are more highly refined to achieve low aromatic and low sulphur contents. They are referred to as ‘Low Toxicity’ or ‘Clean Oils’. Offshore and in environmentally sensitive areas, the use of ‘low toxicity oil’ muds is normally permitted within limits. In general terms, these muds are less toxic than diesel-based muds, but more toxic than water based muds.

1.7.2

Composition Oil muds are fabricated by emulsifying water in oil. The water is broken down into fine droplets by shearing. These droplets are held in suspension by emulsifiers which act on the surface of the droplets. The chemistry of emulsifiers can vary considerably. In general, their molecular structure incorporates hydrophilic groups, which are attracted, to the water droplets and oleophilic groups, which remain in the oil phase. Most oil-based muds contain in the rangr 70-90% oil, 10-30% water. To obtain a stable emulsion, there must be sufficient emulsifier present to keep the entire water tied in. the higher the water content, the more emulsifier will be needed. In addition to emulsified water, oil muds contain viscosifiers, fluid loss additives weighting agents in the same way as water-based muds. However the additives are different.

1.7.3

The Water Phase The water phase is not continuous, but a series of emulsified droplets, coated with emulsifier. It is not available to easily react with water sensitive formations. Thus inhibition is not a problem in the same sense as for water-based muds. However, when drilling shales, transfer of water from the mud to the formation is possible. The mechanism is osmosis. Shales contain captive water of a definite salinity. If the salinity of the muds water phase is matched to the salinity of this formation water, no interaction will occur. Too low a water phase salinity will result in formation hydration giving soft cuttings. Too high a salinity will result in dehydration, giving brittle dry cuttings. In practice, the best way to achieve the correct salinity is by observing the cuttings at the shale shakers. The objective is for the cutting to be dry and firm. In most cases calcium chloride, or sodium chloride brines are used in the place of water for the water phase. In some areas where deposits of magnesium chloride occur, magnesium chloride brine is used.

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1.8

MUD ADDITIVES Our choice of additives is normally restricted to the following common products:

1.8.1

Dissolved Additives Na2CO3 or NaHCO3 NaOH or KOH Ca (OH) 2 or CaSO4 KC1 NaC1 CaC12, CaBr2, and ZnBr2

: to reduce Ca++ content of water : to provide high pH and remove Mg++ : as a source of Ca++ : as a source of K++ : to prevent solution of salt on the formation : to provide extra density.

1.8.2

Viscosifirers Bentonite Xanthum Gum Guar Gum CMC PAC HEC

: naturally occurring clay : synthetic bioploymer : natural polymer : modified cellulosic polymer : modified cellulosic polymer : modified cellulosic polymer

1.8.3

Filtration Control Additives Bentonite Starches CMC and PAC Polyacrylics Resin blends

: naturally occurring clay : natural/modified natural polymer : modified cellulosic polymer : synthetic polymers : synthetic often blended with lignites

1.8.4

Dispersants and Thinners It is necessary on occasions to reduce the viscosity of the mud. In most cases this can best achieved with improved solids control and dilution with water phase premix or fresh mud. Where this is not possible, dispersants are. The most common in water based muds are: Lignite Lignosulphonates Tannin Sapp

: natural product : modified natural product : natural product : sodium acid pyrophosphate

Under normal circumstances, the use of dispersants is avoided, since they disperse drill solids into the mud. This makes solids removal difficult. Their main application is in high temperature muds. Here many of the polymers do not work and high temperature gellation can cause rheology problems.

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1.8.5

Weighting Agents Extra mud density can be achieved by dissolving solids in the base fluid. Unfortunately, this causes a major change in the water chemistry, which limits the choice of other mud additives. Inert solid weighting agents are normally used: Calcium carbonate Barytes Iron oxide Galena

1.8.6

: naturally occurring mineral : naturally occurring mineral : naturally occurring mineral : naturally occurring mineral

Other Products In addition to the above, other products are sometimes added for specific purposes. Examples of this would be: · · · · ·

Defoamers Wetting agents Lubricants Lost circulation materials Flocculants.

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1

DIRECTIONAL DRILLING

1.1

INTRODUCTION Some assemblies used in directional drilling have already been described in the preceding section. These will be elaborated upon here, but the main purpose of this section is to describe the methods used in determining the location of the bit, rotary table and target in relation to each other and in relation to a fixed set of co-ordinates.

1.2

CO-ORDINATE SYSTEMS Co-ordinate systems are used to define the location of points on the earth’s surface. The most commonly used of these systems are polar co-ordinates which are used on maps. The position of a point is defined by its distance (in degrees) from two fixed lines of reference; these being the Equator and the Greenwich Meridian. For example, the co-ordinates of ‘Well X’ in the North Sea are: 57o 56’ 44.3” N 1o 26’ 26.9” E The most commonly used system of co-ordinates in the oil industry is the Universal Transverse of Mercator or UTM. In this system, the earth is divided into sectors. Each sector is 6 degrees wide and 8 degrees high and is assigned a number (1-60) for its location east of the 180o meridian and a letter (C-X, excluding I & O) for its position north of 80oS. So, the sectors covering the majority of the North Sea are sectors 31U and 31V. Co-ordinates within each sector are measured in metres North/South of the equator and metres east of a line 500 km to the west of the central meridian running through that sector; See Figure 1. For example, the surface location of the same ‘Well X’ in UTM are: Sector 31V: 6423868 MN 407697 ME

1.3

DECLINATION AND CONVERGENCE Unfortunately, the direction in which a compass needle points (magnetic north) is not the same as the direction shown on a map (Grid North) or the direction of the true North Pole (Geographic North) and so adjustments for the difference must be made in directional drilling. Declination is the angle between the true north and the angle shown on the magnetic pointer. Convergence is the angle between true north and grid north. This issue is further complicated by the fact that magnetic declination changes because the magnetic north pole is not stationary, but changes its position from time to time. The actual declination for a location on a particular day can be found from charts and tables.

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DIRECTIONAL DRILLING

Figure 1 – Co-ordinate Systems

2

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1.4

WELL PLANNING In planning a well, it is essential to know the co-ordinates of the rotary table and the target to allow the well path to be designed. We must also decide how often we are going to survey the well to ensure that we are within the specified target tolerance; this will depend on the allowable size of the target and the accuracy of the survey tool we select. Once the rig is on location, a site survey should be carried out to determine the exact rig location compared to the planned location.

1.5

SURVEYING

1.5.1

Magnetic Single Shot This is the most commonly used survey instrument. It is cheap and easy to use. The tool consists of the following: · · · · · · · ·

An electronic timer which is used to give a pre-set time before the survey is taken. A camera section, containing film, lens and lamp. A compass and inclination combination unit which the camera focuses upon. A battery section to provide power for the lamp and timer. A sealed survey barrel in which all of the above is held. A set of weights or ‘sinker bars’ which are used to carry the tool to the bottom of the string. A shock-absorber to reduce the effect of impact upon the instrumentation. A ‘spear point’ or hook on top to allow the survey to be recovered.

Also required for this survey is a ‘baffle plate’ or ‘Totco ring’, which is a grid clamped between two tool joints for ‘catching’ the tool. The survey must be run inside non-magnetic drill collars. To run a magnetic single shot, the camera is loaded with film, new batteries are always installed, the correct angle unit is installed for the appropriate inclination range e.g. 0-16o or 16o-32o, etc. The timer is set to allow sufficient time for the tool to drop; approximately 1000 ft. per min. plus 5 mins. safety factor. The tool is switched on and placed inside the housing. It is then picked up and dropped down the string which is stationary. After the pre-set time, the lights illuminate the angle tool and give an image on the film. The lights switch off after 20 seconds. The tool is recovered by running a wireline ‘rope socket’. Once on surface the film is dropped into a development tank and a picture is given within 3 minutes. The inclination and azimuth are then read.

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1.5.2

Magnetic Multi-Shot This tool is generally used as a check on the magnetic single-shot surveys taken during a hole section. It is very similar in appearance to the single shot and is run in the same manner. However, instead of having a single film disc, the tool has a real of film and can be set to take pictures at regular intervals – usually about 20 seconds. The tool is dropped when the section TD is reached. After the tool has reached bottom and taken its first picture, the string is pulled from the hole and the driller stops at each tool joint to allow a survey to be taken. Usually a technician will be present with a stop-watch to synchronise the surveys with the stops made by the driller. There is sufficient film to allow tripping so that perhaps 1 in 4 pictures carries a useful survey.

1.5.3

Gyroscopic Single Shot This tool gives the same information as the magnetic single shot, but is run on wireline. The tool is not in common use as it can only be effectively run to about 2000 ft. However, it does have the advantage of being free from magnetic interference and can be run inside casings, etc.

1.5.4

Gyroscopic Multishot This tool is very similar to the magnetic multishot in that it contains a reel of film and is normally run inside drill pipe. The difference is that this tool is free from magnetic interference and can therefore be run inside casing. For this reason, the gyroscopic multishot is usually used to give the final definitive survey from the bottom of the well to surface once drilling is complete. A gyroscopic multishot is also available for running on wireline.

1.5.5

Measurement Whilst Drilling (MWD) One of the major advances in surveying in the last ten years has been MWD. This system permits surveys to be taken rapidly without having to drop tools into the string and without the use of wireline. There are several systems available, but all are the same in principle. The survey tool is permanently housed in the string inside a non-magnetic housing. Data is transmitted to surface by a ‘pulsar sub’ which encodes the survey information in a series of binary pressure pulses in the mud, which are picked up at surface by a transducer and decoder by computer to give the survey; See Figure 2. To take a survey requires the driller to stop rotation for perhaps 30 seconds. When using MWD, it is normal practice to establish a ‘benchmark’ survey at a particular point (normally the casing shoe) and to check the tool each time the string is run past that point. This acts as a ‘double check’ on the data from the tool. Other MWD tools are also available to provide information normally obtained by wireline logging (e.g. gamma ray and resistivity).

4

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Figure 2 – MWD Used in Directional Drilling

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1.6

DIRECTIONAL DRILLING ASSEMBLIES

1.6.1

Kick-Off Assemblies The most common method of kicking-off a well today is the bent sub-motor combination; See Figure 3. The principle of this system is that the string is not rotated above the bent sub. Thus, the motor can be ‘pointed’ in the right direction and the well kicked-off as required. The motor is powered by the mud being pumped down the string and this in turn causes rotation of the bit. Non-magnetic drill collars are usually run above the bent sub to allow surveys to be taken for checking the path of the well. The angle of the bent sub and the length of the motor must be added to give the correct bottom-hole inclination and depth. Another kick-off method which is becoming less common today is the use of a ‘whipstock’ which is a mechanical kick-off tool run on the drill string. Once the string is run in the hole and orientated, it is lowered to bottom and the whipstock becomes engaged in the bottom of the hole by a chisel point; this prevents rotation of the whipstock. The string is then rotated and kick-off commences. This method only allows a short section to be drilled before changing to a build assembly as stabilisers cannot be run through the whipstock.

1.6.2

Hold Assemblies Hole angle is held using a packed hole assembly; See Figure 2:3. Normally this assembly will continue to drill the well along its present tractory. However, formations can have an affect upon the assembly which may necessitate the use of additional stabilisers and larger diameter drill collars.

1.6.3

Drop Assemblies To drop hole angle, the pendulum effect is used. A gentle drop can be achieved using a light pendulum assembly, but if a rapid drop-off is required, then an aggressive pendulum assembly would be used. Again, the position of the point of contact relative to the bit determines the rate of drop.

1.6.4

Effect of Weight on Bit and Rotary Speed Weight on bit (WOB) and rotary speed (RPM) have a significant effect on the performance of directional assemblies. High rotary speeds will cause the assembly to stiffen and drill in a straighter line, whereas low RPM will reduce stiffness and allow the assembly to build or drop more rapidly. Conversely, high WOB will cause a greater build or drop rate by bending the assembly whereas low WOB will permit straighter drilling. WOB and RPM both have and affect upon the point of contact of the assembly with the wellbore.

6

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Figure 3 – Motor and Bent Sub

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Figure 4 – Whipstock Used for Kick-Off

8

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1.6.5

Steerable Systems When using a downhole motor and bent sub, it is possible to ‘steer’ the assembly in the required direction. This method has traditionally involved the use of a downhole gyroscope or magnetic survey which is connected to a surface computer via wireline. A visual ‘direction’ display is installed on the driller’s console to allow him to ‘see’ in which direction the hole is being drilled. He can then make the necessary adjustments in direction by simply rotating the stationary string a few degrees to bring the well back on course. With the advent of MWD systems, it is possible to obtain surveys in the same manner but without the problems of handling wireline. Steering can be achieved in the same manner.

1.7

THE DIRECTIONAL DRILLER During most directional drilling activities, a directional driller will be on site. His job is to ensure that the well path is drilled according to plan. He does this by plotting all the survey data (measured depth, inclination and azimuth) on a table and uses standard equations and tables for declination to allow him to covert this information into rectangular co-ordinates which he can then plot on a chart against the proposed well path. By doing this he knows precisely what the path of the well is. If the well begins to deviate excessively from the proposed path, he will make recommendations for changes to the BHA, WOB or RPM, to bring the well back on target.

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1.8

10

DIRECTIONAL DRILLING EXERCISE

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DIRECTIONAL DRILLING EXERCISE GENERALISED RULES

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SELECT

WEIGHTS FROM THE FOLLOWING RANGE:

HIGH WT. ON BIT 55,000 lbs

‘REAMING’

SELECT

------------------

LOW WT. ON BIT 20,000 lbs

RE-DRILLING THE HOLE SHAVES OFF THE LOW SIDE OF THE HOLE AND DROPS ANGLE. REAM THE HOLE

- ONCE - TWICE - THREE TIMES

ROTARY SPEEDS (RPM) HIGH RPM LOW RPM

TENDS TO MAKE THE BIT DRILL STRAIGHTER IN DIRECTION TENDS TO MAKE THE BIT ‘WALK’ TO THE RIGHT

SELECT HIGH RPM 150

-----------------------

LOW RPM 50

SOME TURBINE ASSEMBLIES NATURALLY ‘WALK’ TO THE LEFT PUMP RATE IN SOFT FORMATIONS

HIGH PUMP RATE DROPS ANGLE (ESPECIALLY IN THE BUILD UP PHASE)

IN HARD FORMATIONS

PUMP RATE MAKES LITTLE DIFFERENCE TO ANGLE

SELECT HIGH PUMP RATE 600 GPM

12

--------------------

LOW PUMP RATE 350 GPM

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BOTTOMHOLE ASSEMBLIES USED IN DRILLING

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Casing And Cementing

1

CASING AND CEMENTING

1.1

REASONS FOR RUNNING CASING · · · · · ·

Provide a means of controlling well pressure. Permit Circulation. Prevent Collapse of hole. Prevent Fluid Migration. Isolate troublesome zones. Facilitate control of a production well. Types of Casing Conductor Surface casing Intermediate String Production String Liner

Common Size 30" 20" 13 3/8" 9 5/8" 7"

1.2

PHYSICAL PROPERTIES

1.2.1

Length Ranges Casing comes in three range lengths: R1 R2 R3

10 - 25 ft 25 - 34 ft 34 ft

There are different 'grades' of casing which indicate the strength of the sheet. These are colour coded: GRADES

MINIMUM YIELD STRENGTH

COLOUR CODING

H40

40,000 psi

No Colour-Black

J55

55,000 psi

One Band Bright Green

K55

55,000 psi

Two Bands Bright Green

C75

75,000 psi

Light Blue

N80

80,000 psi

Red

C95

95,000 psi

Yellow Band

P105

105,000 psi

White

P110

110,000 psi

White

P110

110,000 psi

V150

150,000 psi

Table 1

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Casing And Cementing

1.2.2

Couplings Various couplings have been developed to perform different functions: API COUPLINGS · STC Short Round Thread Casing · LTC Long Round Thread Casing · BTC Buttress Thread Casing · XL Extreme Line Casing. NON API COUPLINGS · Hydril Super EU. TS · Valorec · Vam.

1.2.3

Standard Bit and Casing Programmes The following tables show API standard bit sizes and the casing size run in the drilled hole. BIT SIZE Programme One 36" (26" bit 36" hole opener) 26" 17 1/2" 12 1/4" 8 1/2" Programme Two 20" 14 3/4" 9 7/8" Programme Three 26" 17 1/2" 12 1/4" 8 1/2"

2

CASING SIZE 30" 20" 13 3/8" 9 5/8" 7" 22" (driven Conductor) 16" 10 3/4" 7 5/8" 18 5/8" / 18 3/4" 13 3/8" 9 5/8" 7"

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1.3

CASING DESIGN

1.3.1

General Casing design is required to ensure that casing run in the well will withstand the various loads applied to it. The principle loadings casing is subjected to are: · · ·

Burst Collapse Tensile.

The worst case loading is considered in each case. 1.3.2

Burst Loading Burst loadings are the net internal pressure load exerted on the casing. The worst case of burst loading usually occurs when a gas kick has been taken and the annulus is filled with gas when the well is shut in. The load exerted on the outside of the casing at this time is the hydrostatic pressure of a column of formation fluid (usually taken to be water.) This external load serves to back-up the casing during burst loading. Therefore, the nett burst load is the difference between the pressure inside the casing and the pressure outside. The point of maximum burst loading in this case is therefore at the top of the casing string where there is a high gas pressure and zero back-up.

1.3.3

Collapse Loading See Figure 1. If the casing is emptied of fluid completely, the worst collapse situation exists. With no internal hydrostatic pressure of the mud, the full formation pressure is exerted on the casing at the shoe; See Figure 2. In this example it is represented by point C, 1,420 psi on the casing design chart; See Figure 3. At the surface the collapse pressure is clearly zero since only atmospheric pressure is acting on the casing. The collapse design line may now be drawn. When exceptional circumstances occur such as casing run in salt formations or in earthquake areas, extra collapse resistance is required and must be designed for.

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Casing And Cementing

Figure 1 – Collapse Loads

4

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Casing And Cementing

1.3.4

Tensile Loading Tensile loading is applied to casing as a result of its own weight and is at a maximum underneath the casing hanger at the surface. Buoyancy reduces the tensile loading on casing. Tensile loading on the casing is increased as a result of running it in directional hole. A formula shown on Figure 2 describes the increase in tensile loading. A critical factor is the outside diameter of the casing, which, if reduced, reduces the tensile loading on the casing. It is for this reason that smaller sizes of casing are selected to be run on the build up sections of directional hole, particularly if rapid changes of angle are expected. Collapse and burst loading on casing are both affected by tensile loading. Tensile loading tends to reduce the collapse resistance of casing. This is a particular problem in deep wells with long casing strings. However, tensile loading has the reverse effect on burst resistance. Burst resistance is increased due to the tensile loading. Temperature effects must also be considered as the elongation of the casing can effect all loadings. The Drilling Engineer will make use of standard tables and equations to allow for the effect of tension and temperature.

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Figure 2 - Tensile Loads

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Figure 3 - Typical Casing Design Chart

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Sure Seat Float Valves The primary valve type used by Weatherford in building the world class 'Sure Seal III' float shoes and collars in the 'poppet' or 'spring loaded cone'. The attributes of this type of valve are: · · · · ·

Large flow area Long flow life, > 24 hrs in normal conditions Temperature stable to 400 deg.F Capable of holding high back pressures Meets and exceeds IIIC requirements set out in RP10F.

Figure 4 - Sure Seat Float Valve

Components of the Sure Seal 3 Valve

Figure 5 - Components of the Sure Seal 3 Valve

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Sure Seal III Valves Sizes Sure Seal 3 Valves are sized by the diameter of the orifice on top of the valve. Here you see all three basic sizes: · · ·

3 1/4" 2 1/2" 1 7/8"

All three valves when used in the matching size casing are capable of exceeding RP10F requirements

Figure 6 - Sure Seal III Valves Sizes

Common Questions on Float Equipment Pressure Ratings Weatherford premium thread float equipment shells meet or exceed the casing burst, collapse, and tensile ratings of the matching threaded casing unless otherwise specified. The OD and ID of the float shells match the connection OD and ID unless otherwise specified.

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Close Up of 450 Differential Fill Float Valve The purpose of Differential Fill Float Valves is to allow a metered amount of fluid back into the casing. The differential areas on the sliding sleeve are built to allow approximately 10% less fluid inside the casing as compared to the annulus. The components of this valve are all aluminium.

Figure 7 - Close Up of 450 Differential Fill Float Valve

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Multiple Stage Cementing Tool Activated using free fall plug (based on 3-5 min./1,000 ft.) · ·

Standard accessories are aluminium New Plastic Opening Cone available in some sizes, easier PDC drillout

Single unitary sleeve. No pressure traps. Clear surface indications of opening. Special viton seals available. Opening pressure ~700-1,000 psi. Closing pressure ~1,200 psi. over lift.

Figure 8

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Hydraulically Operated Stage Tool Opening Process does not require a free fall plug, therefore operates at any hole angle. Aluminium seats for easy drill up. Can be converted with pump down plugs or free fall cone if required. Unitary sleeve design. Can be run in conjunction with annular casing packers.

Figure 9

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Pack-Off Stage Tool Basic tool is Model 751 with integral inflatable packer. Packer can withstand up to 4,000 psi. differential when properly inflated. Pump down plugs allow tool to be run in high angle to horizontal holes. External shear pins are used to adjust opening pressure at rig site. Unitary sleeve design.

Figure 10

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When we reach the casing point, the mud is conditioned and the drill string assembly is removed and casing running begins!

Rheometers such as this one are used to check the rheological properties before running and cementing the casing.

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Then after a wiper trip, the drilling assembly is pulled and the casing running operation begins.

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The Casing Running Procedure The first tool run on the casing string is the Float Shoe, it's purpose being to guide the casing into the wellbore.

Figure 11

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Casing Running - Shoe Track The next step is to run either 1 - 2 joints of casing, followed by the float collar, this makes up the 'shoe track'. The collar is thread locked onto the joints to prevent backing off during the drillout process (same as welding).

Figure 12

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Casing Running Procedure Hardware such as centralizers, stop collars, stage tools and cement baskets are added as the casing is run until finally TD is reached. Then the cementing process is ready to begin! Pipe movement begins at this point.

What Channelling Looks Like!

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Guide Shoe

Figure 13 – Guide Shoe

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1.3.5

Casing Design Chart We have seen how the casing design chart; See Figure 3, is constructed by considering burst and collapse loadings on the casing at the surface and the casing shoe. The engineer now has the task of selecting the correct weights and grades to be used in the string. More than one weight and grade is used for economical reasons (less steel required with thinner wall casing) and to reduce tensile loading. A set of casing tables with the following information is used. Size

Weight

OD (ins)

T&C

Grade

ID

Drift

Collars

Burst

Pipe Yield

(ins)

(ins)

Pressure

Pressure

Strength

(psi)

(psi)

(1000 lbs)

(lbs/ft) 13 3/8”

48.00

H-40

12.715

12.559

770

1,730

541

54.50

K-55

12.615

12.459

1,130

2,730

853

61.00

K-55

12.515

12.359

1,540

3,090

962

68.00

K-55

12.415

12.259

1,950

3,450

1,069

72.00

L-80

12.347

12.191

2,670

5,380

1,661

Table 2 - Casing Properties & Dimensions

Using the casing design chart, the engineer selects a casing weight and grade which has a burst resistance greater than the burst design line. He must also check to see that the same casing weight and grade has a collapse resistance greater than the collapse design line. In the example of Figure 13, the engineer selected 54.5-lbs./ft. weight and K-55 grade casing from the surface to 600 ft. At 600 ft., it was realised that a lower weigh and grade of casing could be used, namely 48 lbs/ft, H-40 casing down to 1,500 ft. This casing could have been used all the way to the casing shoe as far as burst loading is concerned. However, the collapse resistance of this weight and grade of casing is insufficient past 1,500 ft (see collapse design line). A higher grade of casing had to be used which had greater collapse resistance, namely 54.5 lbs/ft weight and K-55 grade of casing. In this way several different weights and grades of casing will be used in a casing string. A check must always be made to make sure that the tensile yield strength of the casing is not exceeded. It can clearly be seen that loading casing string of different weights and grades can be a logistical nightmare! For this reason, the number of casing weight and grade changes is restricted to ensure that the casing is picked up and run into the hole in the correct order.

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1.4

CEMENT AND CEMENTING See Figure 14

1.4.1

Reasons for Cementing Casing · Supports vertical and radial load on casing · Controls the formation pressure whilst drilling ahead · Isolates porous formations · Helps protect against corrosion.

1.4.2

Why Use Cement Cement is ideal for the job on hand and has been used since the beginning of the oil industry for the following reasons: · · · ·

Low Cost World-wide Availability Consistent Quality Flexible properties.

1.4.3

Manufacture of Cement Limestone, Clay and sometimes iron and aluminium oxides are ground together and heated to 2,600 – 2,800OF in a rotary kiln. The resultant clinker is mixed with 1.5 - 3% by weight Gypsum (CaSO4-2H2O) which controls rate of settling and hardening. The resultant is Portland Cement.

1.4.4

Properties Portland Cement is made up of the following: 3 CaO SiO2

Prevalent-Principle strength producing material.

2 CaO SiO2

Slow hydrating compound, which gives gradual gain in strength.

3 CaO A12O3

Promotes rapid hydration- Controls initial set and thickening time. For high sulphate resistance use less than 3O.

4 CaO A12O3Fe2O3

Low hydration heat.

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Figure 14 - A Typical Cased and Cemented Well

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1.4.5

1.4.6

Standards API Cement Mixes Class A 0 – 6,000 ft - 170OF: No special qualities required. Class B 0 – 6,000 ft

- 170OF: Moderate sulphate resistance.

Class C 0 – 6,000 ft

- 170OF: Regular or high sulphate resistance.

Class D 6,000 – 10,000 ft

- 230OF: Regular or high sulphate resistance.

Class E 6,000 – 14,000 ft

- 290OF: Regular or high sulphate resistance.

Class F 10,000 – 16,000 ft

- 320OF: Regular or high sulphate resistance.

Class G 0 – 8,000 ft neat

- 200OF: Can be used with additives over ranges Class A-E.

Class H 0 – 8,000 ft neat

- 200OF: Can be used with additives over ranges Class A-E.

Cements Additives Various additives are mixed with cement slurry for any of the following reason: 1. 2. 3. 4. 5. 6. 7. 8.

1.4.7

1.4.8

1.4.9

To vary the density between 10.8 - 20 ppg To increase of decrease strength To accelerate or retard setting time To control filtration rate To reduce viscosity To increase corrosion resistance As lost circulation material To improve economics.

Lightweight Additives Extra water causes the particles to separate and settle out. 1.

Bentonite

: For each 1% by weight add extra water 3 - 5% by weight.

2.

Diatomaceous Earth

: Similar effect to gel, less strength reduction.

3.

Perlite

: Ground volcanic lava.

4.

Gilzonite

: 25 - 50% with cement.

5.

Pozzlan

: 50 - 50 with cement gives greater strength and better sulphate resistance. Also called Pozmix.

Heavyweight Additives Barytes (SG 4.2)

: 35.03 ppg

Hematite Ore (SG 5.05)

: 42.12 ppg

Ottowa Sand (SG 2.1)

: 17.51 ppg

Accelerators Calcium Chloride

: 2%

Sodium Chloride

: 2 - 2.5% (retards with high concentrations)

Seawater

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1.4.10

Retarders 1. Calcium lignosulfonate for temps up to 260OF. 2.

Calcium lignosulfonate + organic acid for temps above 260OF.

3.

Borax.

4.

Diacel LWL, i.e. Carboxymethyl-hydroxyeethyl-cellulose (which also controls filtration rate).

1.4.11

Low Water Loss Slurries · Controls filtration rate especially during squeeze jobs to prevent premature setting · Diacel LWL · Halad 9 (Halliburton) · Halad 11 (Halliburton) · Flac (Dow Chemicals) · Liquid Latex.

1.4.12

Lost Circulation Materials Granular, Fibrous or Flake forms of: · ·

Nut Shells Cellophane.

These must not contain any substances, soluble in water that would affect thickening times.

1.5

SPECIAL CEMENTS ·

Diesel oil Cement Cements is suspended in the diesel, on contact with formation waters it sets in place.

·

High Temperature Cements High temperature can effect the strength of the cement. Therefore, the following additives may be used. Add 30% silica flour - prevents strength retrogression and improves bonding. 'Pozmix 140' (Halliburton) - pozzalons-line+chemicals.

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1.6

PRIMARY CEMENT PRACTICES For the best cementing job, concentricity of the pipe in the well bore is very important. The more concentric the pipe the easier it is to remove the wall cake and get a coating of cement uniformly around the pipe, thus the bond will be complete, i.e. pipe to cement to formation. Without a good bond, the cement job becomes a big problem involving remedial practices, which can be extremely expensive. So why not pay a little extra to ensure primary job is done well in the first place.

1.6.1

Flow Patterns There is three basic type of flow in the well bore: 1.

Plug Flow

2.

Laminar Flow

3.

Turbulent Flow.

Turbulent flow gives the best cleaning or scouring effect. The faster the rate of flow, the nearer to this turbulence we are likely to be. If the pipe is not concentric in the well bore, turbulent flow if difficult to attain all around the pipe and the cement will tend to 'channel'.

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1.6.2

Effective Centralisation See Figure 15. This is more critical in deviated wells than in straight hole. Whilst having enough centralisers to centralise the pipe, we must not use too many as we will be unable to get the casing into the ground, the frictional forces will be greater than the pipe weight. Available are the following: · · · ·

Straight Bow Spiral Bow (L or R) Positive Liner Pilots.

Figure 15 - The Importance of Centralisation

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1.6.3

Well Cleaners These are used to assist in the clearing the mud cake off the formation when running the pipe, by reciprocation or rotation. There are two types: · ·

1.6.4

Turbulent Flow There are accessories available to help the fluid to gain turbulence. These are: · ·

1.6.5

Scratchers Well bore wipers.

Turbo Clamp Hydrobonders.

Stop Collars To secure this 'jewellery' to the pipe 'stop collars' are sometimes required.

BEWARE! 1.6.6

Too much jewellery can cause the pipe to 'hang up' in the well bore.

Cement Contamination To prevent cement contamination by the drilling mud, washes and plugs are often pumped ahead of the slurry. The washing water and chemicals assist in cleaning the well bore as well as acting as a spacer, but if too much water is pumped, the hydrostatic pressure can be dangerously lowered and a kick may occur up the outside of the casing. The first wiper plug cleans the inside of the casing pushing an accumulated mud film ahead and landing in the float collar, the diaphragm bursts and allows the cement to be pumped out of the casing. The final plug separates the cement from the displacing mud, and signals displacement complete when it 'bumps' on the first plug. The casing, from the float to the shoe will be full of cement, if there is any contaminated cement collected by the final plug it will be inside this portion. The cement around the shoe joint must be of the best quality. In the float and shoe are ball valves on spring which will not allow the cement to back flow.

1.6.7

Evaluation of Cement Job In the past, cement jobs have been assumed to be good, unless there was immediate evidence to the contrary. Now, however, cement bond log (CBL) is normally run on wireline after drilling the next hole section. It might be necessary to perform and squeeze if these logs show that the primary job is not all that it might be.

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1.7

PROCEDURE FOR CASING AND PRIMARY CEMENT JOBS PRE-CEMENT JOB CHECKS 1. Lay out casing. 2. Casing tally. 3. 'Rabbit' and check threads. 4. Make sure casing is in the correct sequence. 5. Correct dope and enough dope. 6. Elevators and tongs. 7. Cement head and plugs. 8. Circulating swedge. 9. Mix water cement and additives. RUNNING CASING 10. Condition hole. 11. Slick line measure of hole and tally drill pipe. 12. Bakerlock shoe and first two or three joints. 13. Check float equipment. 14. Remove wear bushing. 15. While running casing, check calculated displacement to trip tank. 16. Keep pipe moving to avoid sticking and circulate. 17. Rig up cement head and plugs. 18. Pump water or chemical spacer to remove mud cake. 19. Drop bottom plug. 20. Load top plus (if not already in cement head). CEMENT JOB 21. Cement job, lead and tail slurry, checking returns for lost circulation and cement contamination. 22. Drop top plug with 5 bbl cement + 10 bbl water. 23. Displaced calculated volume keeping careful check on strokes. 24. Slow down at end and bump plug no more than 1,000 psi. 25. Bleed off pressure and check for flow back if there is any, hold back pressure, and wait for pressure samples to set. 26. WOC. POST CEMENT JOB 27. Remove BOP if necessary. 28. Set slips and pack off. 29. Cut and bevel casing. 30. Install next well head section. 31. Nipple up BOP. 32. Test BOP and casing. 33. Run CBL if required. 34. Drill out shoe. 35. Leak off test. 36. Make hole.

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DRILLING FROM A FLOATING VESSEL

1.1

INTRODUCTION Compared to drilling a well on land or from a fixed installation.. drilling from a floating vessel poses unique problems. Environmental forces tend to move the vessel in both horizontal and vertical directions and these movements require to be either controlled or compensated for if drilling operations are to proceed successfully. The fact that the wellhead and primary well control equipment are located on the seafloor is also a source of many potential difficulties. Horizontal vessel displacement is limited by the mooring system which is designed to hold the vessel over the wellhead for as long as possible whatever the weather conditions. If vertical motion was not compensated for, then many problems could occur. Weight on the bit would be difficult to control and there would be excessive wear between drillpipe and BOPs or casing. Logging would produce curves difficult to interpret and landing pipe on the pipe rams could become a very hazardous operation. Successful development of drill string compensators and tensioners over recent years has overcome these problems to a large extent. The remote location of the BOPs and the long lengths of hydraulic control hoses needed lead to delays in their operation. Extra time is required for BOP testing, inspection and troubleshooting compared to the situation where the BOPs can be conveniently located directly under the drill floor. Additional equipment such as the riser, slip joint and diverter all increase the complications of floating drilling. The remainder of this manual will attempt to explain the nature of these problems in more detail and the current state of drilling technology that has been developed to overcome them. In the course of this, it should become apparent that drilling a well from a floater - especially in a relatively hostile environment - is a complex operation requiring experienced, well trained personnel to plan and direct it.

1.2

TYPES OF MOBILE RIGS Floating drilling operations can be conducted from one of 3 types of mobile vessels: · Barge type · Ship type · Semi-submersible or column stabilised type.

1.2.1

Barge Type A flat hulled barge mounting the drilling equipment is the simplest form of mobile unit. It is therefore the most economical, but can only be employed in sheltered waters. Most barges employ land drilling techniques (for example with a cantilevered derrick and drilling through a wellhead installed on a fixed platform) or jack up drilling techniques (drilling through a mudline suspension wellhead). Some barges use subsea drilling techniques with the BOPs located on the seabed, the derrick being located over a moonpool in the centre of the barge. All barges maintain station by being anchored in position and require towing between locations.

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1.2.2

Ship Type In this design a conventional hull-shaped vessel, possibly with sponsons added on for extra lateral stability, is used to support the drilling equipment The position of the rotary table relative to the ship's centre of gravity is an important factor in considering the ship's stability. In general these units are self propelled and are very mobile. A modem drill ship can average 14 knots transit speed in good conditions and this, together with a high drilling equipment storage capacity, means that such a vessel is ideal for drilling consecutive wells in different parts of the world or in 'frontier' waters. To maintain position, drill ships are either moored or rely on dynamic positioning. The conventional mooring system consists of 8 or 10 anchors and will maintain the vessel on a fixed heading. On one design all the anchors are connected to a turret in the centre of the ship about which the vessel can rotate and 'weathervane' - i.e. always head into the prevailing weather. A dynamically positioned vessel maintains station by constantly manoeuvring itself with computer controlled thrusters (located transversely fore and aft) and its main propulsion. Since such a vessel would usually only be connected to the sea floor via the drilling riser and possibly guidelines, it is able to leave location relatively quickly - a necessary requirement if working amongst the icebergs off the Labrador coast, for example. The chief disadvantage of the drill ship is its unfavourable motion characteristics in heavy weather, particularly in a beam sea, hence the attraction of a ship capable of weathervaning.

1.2.3

Semi-Submersible Type In order to overcome some of the drawbacks of drillships, and in order to allow drilling to take place economically and safely in more hostile conditions, the semi submersible vessel was developed. This relies for stability on pontoons which can be ballasted down to a depth of some 70 ft and from which columns support the main deck some 40 ft – 60 ft above sea level. Most recent semis have 2 pontoons (catamaran type) and from 4 to 8 columns, other designs have 3 pontoons (or footings) and columns (135 type) or 5 pontoons and columns (pentagon type). Heavy cross members and bracings interconnect the columns and pontoons. However, due to the nature of their construction, semis do not possess the same structural integrity as drill ships. As a consequence of the relatively high deck and, therefore, the high centre of gravity, a semi-submersible, if it is to remain stable, can only carry a limited deckload - generally in the order of 2000 tonnes although some of the more recent designs can double this figure. Deckload limits are reduced even further when the rig is in transit, since in this situation the vessel has to ballast up to a shallow draft to enable the cross members to clear the water. Unless the rig is prepared to move ballasted down and therefore very slowly, load carrying capacity between locations is not very great. Most modem catamaran semis are self propelled and can travel at UP to 8 knots when assisted by a tug. Older, non-self-propelled designs, such as the 135 type, are less efficient when under tow and require 3 tugs to move at even 3 or 4 knots. Apart from a few that use dynamic positioning to maintain station, all semis are usually anchored on location.

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DRILLING FROM A FLOATING VESSEL Construction and operating costs for semis tend to be higher than for drill ships. In general, semis are designed and equipped primarily to work in rough weather areas. A drill ship comes into its own when the requirement is for mobility - if several wells are to be drilled in far apart or remote locations. It should be borne in mind, however, that if a comparison between the two types of vessel is to be made, the skill and training of the personnel involved can affect performance just as much as station keeping equipment, motion compensating equipment or location of the rotary table relative to the centre of gravity. 1.2.4

Setting Anchors While a rig is being brought onto location, the workboats are used to position anchors. The anchors are picked up from the rig and put on the workboat, the anchor chain passes from the winch, or wildcat as it is sometimes called, through a swivel to the anchor. As the workboat pulls the anchor to the tripping point, the anchor chain is paid out through the anchor winch. When the correct amount of anchor line has been paid out, the workboat drops the anchor and attaches what is termed the ‘permanent line’ to it. A buoy is dropped to mark the spot where the anchor is and the line is tensioned up by means of the anchor winch. Normally, pre-tension is taken on each line in excess of its usual operating tension. For instance, if a typical operating tension is 200 tons, the pre-tension on the line may be 200 tons. This allows for additional bolting power should the rig be subjected to bad weather. When on location, anchors are set, the rig is ballasted down and then drilling can start.

1.2.5

Running the Temporary Guide Base Before running the temporary guide base, a check is made on the condition of the sea floor to ascertain if the sea floor is hard or soft which could cause problems. A drilling assembly is picked up, run down to the sea floor and is pushed into the sea floor to ascertain softness of the sea floor. If the sea floor is soft it will be necessary to modify the temporary guide base. In normal conditions, the temporary guide base is positioned below the rig floor in the ‘moonpool’ area of the rig and has the four guide lines attached to it, the temporary guide base (TGB) is filled with weighting material, typically barites, and the whole assembly is picked up on a drill pipe running tool and run down to the sea floor paying out the four guide lines; See Figure 1.

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Figure 1 – Landing Temporary Guide Base

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DRILLING FROM A FLOATING VESSEL Once the temporary guide base is down at the sea floor, tension is taken up on the 4 guide lines and the running tool is released. Using a special utility guide frame, a 36” drilling assembly is lowered down to the sea floor and is stabbed into the temporary guide base. This drilling assembly usually consists of a 26” bit and a 36” hole opener. Once drilling starts, the guide frame is retrieved and 36” hole is drilled down to the setting depth for the first string of conductor casing. The setting depth of the 30” casing varies according to water depth. The 36” hole is conditioned with high viscosity mud and the cuttings are swept from the hole.

Figure 2 – SPUD 36” Hole Opener

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1.2.6

Running 30” Casing To run 30” casing from a floater the permanent guide structure (PGS) is positioned in the moonpool area below the rotary table. The permanent guide structure is supported on the hydraulic retractable spider beams some 40 ft below the rig floor. The 30” casing is made up joint by joint starting with the shoe joint. Special casing connectors are used to make up 30” casing on a floating rig because of the problem of rig movement which would cause conventional threaded connections to cross thread and not seal. These snap type connectors are usually welded on to the 30” casing. The 30” casing is pushed through the guide base structure as it is mated up joint by joint. The 30” housing or wellhead is mated up to 30” casing on the rig floor. Next, drillpipe is run inside of the 30” casing to within about 15 ft of the casing shoe. Then the 30” running tool is made up to the drillpipe and connected to the 30” housing. The 30” casing is now lowered on drillpipe down to the permanent guide base where the 30” casing is bolted to the permanent guide structure (PGS). The whole assembly is now one. The permanent guide structure, the 30” casing and the drill pipe running tool. The assembly is lowered to the sea floor with the 30” casing landing into the 36” hole; See Figure 3. The permanent guide structure lands on top of the base on a special gimble. When landed, it is essential that the permanent guide structure should be within one degree of level. If not, problems could occur when running the blowout preventer stack down to the sea floor. Once level, the 30” casing can be cemented into place. This is usually done by pumping cement down the drill pipe which runs down inside the 30” casing, through the 30” casing shoe and coming up the annulus between the 30” casing and 36” open hole. Cement returns at the sea floor and it is usual practice to send divers or remote operated vehicles (ROVs) down to observe this cement return. Once the 30” casing is cemented in place, the running tool is released and the drill pipe is pulled back to the rig.

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Figure 3 – Running Permanent Guide Base with 30” Conductor

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DRILLING FROM A FLOATING VESSEL

Figure 1:4 – Running Sub-Sea Conductor

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1.2.7

Connecting the Riser and Diverter System At this point in the well, it is usual practice to connect the diverter and riser system to enable shallow gas to be controlled. However, on some operations, 26” hole is drilled directly underneath the 30” casing without connecting the riser. To connect the riser, a hydraulic latch or pin connector is used to latch on to the 30” housing. On top of the connection is a flex, or ball joint which allows the angular misalignment of the rig with respect to the wellhead. On top of the flex joint, marine riser is run back to the rig; See Figure 5, this shows the options of drilling a 26” hole with and without a riser. To compensate for the vertical movement of the rig, a slip joint is used. This is a telescoping joint of riser connected to the diverter directly underneath the rig floor. In order to maintain tension on the riser, the outer part of the slip joint is attached to riser tensioners. The diverter is connected to the inner part of the slip joint which is used in the event of a shallow gas influx to diverter this influx away from the rig in a safe manner. A diverter system is used instead of a BOP because shutting a well in on a shallow gas could have the disastrous result of breaking down the formation below and behind the casing and gas blowing out in an uncontrolled fashion at the sea floor. Once the diverter system has been connected a 17½” bit with a 26” under-reamer is used. This assembly is used because typically the riser has a small bore which will not allow the passage of a 26” bit. The under-reamer, a tool which has arms which open out, can pass through the riser yet once pump pressure is activated the 26” arms open out to drill 26” hole below the 30” casing shoe. A 26” hole is drilled down to the casing setting depth for the 20” casing. The 26” assembly is now removed from the hole. Before disconnecting the riser it is mandatory that seawater be circulated into the riser and the well observed to be stable. If this was not done, then there would be the possibility of the well kicking when the riser is disconnected. Once the hole is safe, the riser is disconnected at the hydraulic latch or pin connector and the whole riser assembly is laid down. This is done in order to run 20” casing.

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Figure 5 – Diverter

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Figure 6 – Drilling 26” Hole for 20” Casing

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DRILLING FROM A FLOATING VESSEL

1.2.8

Running 20” Casing A 20” casing is made up of special threaded connectors typically used on a floating drilling operation again to avoid the problem of make-up and cross-threading connections due to the movement of the vessel. Once the string of 20” casing is made up, the 18¾” high pressure wellhead housing is attached to the last joint of casing. In a similar fashion to 30” casing, drill pipe is run down inside the 20” casing on a running tool which typically has a left-hand thread. This is made up to the high pressure wellhead housing and the 20” casing is lowered down to the sea floor on drill pipe. A guide frame may be used to guide the 20” casing into the 30” housing. The 20” casing is lowered down until the 18¾” housing locks into the 30” housing. The casing is cemented in place by pumping cement down the drill pipe through the 20” cement shoe and the 20” x 30” annulus. Cement returns are observed at the sea floor. Care must be taken to ensure that cement does not build up around the high pressure wellhead housing. Once the 20” casing is cemented in place, the left hand running tool is released by right hand rotation and the drill pipe is pulled back to the rig.

1.2.9

Running and Testing the BOP Stack Before running the stack, it is tested by means of a test joint of drill pipe which is inserted in to the stack. The stack is then filled with water and all of the functions are pressure tested to a specified pressure. Usually this is to 5, 10 or 15,000 psi. This test will probably go on while other drilling operations are proceeding. When the stack is actually run, it is moved from its test stump by means of the overhead crane system and positioned on the spider beams in the moonpool. The lower riser package can now be moved off its test stump and connected to the main BOP stack by means of the hydraulic connector. The BOP control system is now attached by means of flexible hose reels. The riser is connected to the lower riser package from the rig floor and the whole weight of the BOP stack is transferred to the riser handling spider on the rig floor. This handling device compensates for the movement of the vessel and prevents damage to the riser as the BOP moves with the vessel movement. Now the BOP stack is carefully lowered to the sea floor by means of the guide lines as joints of riser are added one by one, until the BOP stack lands on the high pressure wellhead housing. The BOP stack is connected to the housing by means of a hydraulic connector. The Wellhead connector works by means of a series of hydraulic systems that pull a cam ring down. As the cam ring is brought down, so the connector locking dogs drive in against the wellhead profile. As the dogs drive in against the profile, so a high pressure ‘AX’ or ‘VX’ seal is energised. This metal-to-metal seal has a pressure rating of 5, 10 or 15,000 psi; the same as the wellhead system. Once the BOP has been latched and a pickup test performed, then the stack is tested. The BOP stack is tested by running a special BOP test plug down inside the riser into the high pressure wellhead housing. The stack is now sequentially closed to function test each ram on the stack. The test also checks the high pressure seal between the BOP stack and wellhead. Occasionally, stack tests fail and a leak is observed in the system. It is then necessary to remove the BOP stack from the seabed to find out the cause of the leak.

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Figure 7 – Drilling System

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DRILLING FROM A FLOATING VESSEL

Figure 8 – Single Stack System Wellhead

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Figure 9 – Wellhead and Wellhead Connector

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1.3

MOTION COMPENSATION

1.3.1

Introduction One of the major problems of floating drilling is to compensate for the relative vertical motion between the drilling vessel and the seabed. A drill string that moves up and down with the rig would soon damage the bit and cause heavy wear inside casing and the BOP stack. Careful control of the hook load is also needed when landing casing or running the stack. Excess heave also adversely affects logging operations and ROP measurement. The use of bumper subs helped to solve some of these problems, though in the drilling mode they only allow predetermined bit weights to be applied. Vessel heave also affects the constant tension that needs to be applied to the riser and guidelines. Initially counter-weights provided this compensation, however these became impractical as drilling moved into deeper and rougher water. The development of passive heave compensators and tensioning systems over the last 15 years has gone a long way to solving these problems.

1.3.2

Motion Compensator Drill string motion compensators use air pressure from a large reservoir to exert a force on a piston from which the load is suspended. As the load fluctuates the variation in force is absorbed by the air reservoir so that the net fluctuation at the bottom of the drill string is as small as practicable. There are two different types of motion compensator: those mounted on the crown block and those mounted between the travelling block and the hook. The former type have the advantage of being fixed relative to the vessel and do not need to be connected to long flexible high pressure air or hydraulic lines, as is the case for the travelling block mounted compensators. On the other hand, their location on top of the derrick does not add to vessel stability. The travelling block mounted designs have proved to be the most popular and so will be described in greater detail.

1.3.3

NL Shaffer This design typically has an 18 ft stroke and has a working load capacity of 400,000 lbs. The main frame either has an integral 6 sheave travelling block (for a more compact overall height) or is rigidly connected to the rig's block. Chains from the main frame passing over sheaves attached to the pistons support the hook frame and hence the drill string. As the vessel heaves upwards, the cylinders retract and the hook moves downwards relative to the rig floor, whilst remaining motionless relative to the bottom of the hole. Air on the piston face side of the cylinder is then compressed and forced out through the 4 air hoses into the air pressure vessels to maintain the level of preset tension. Low pressure (20-40 psi) oil is fed into the rod side of the piston from an air/oil reservoir mounted on the compensator main frame. As the rig heaves downward the system works in reverse. The use of the chain and sheaves permits 18 ft of compensation for 9 ft of piston stroke. By using air instead of hydraulic oil on the piston, face friction effects are greatly reduced and response time is fast. However, it requires that each air line is filled with two automatic shut-off valves and also has a stainless steel safety wire running inside it in case it bursts under high pressure. At its maximum load of 400,000 lbs the system required 2260 psi of air.

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DRILLING FROM A FLOATING VESSEL A speed limiting valve on top of each cylinder, through which the low pressure oil flows, controls the speed at which the piston is extended. When the pistons are fully extended, the hook frame fits into the main frame and a lock bar can be hydraulically activated to lock the two frames together. In this configuration the compensator has a load capacity of 1,000,000 lbs. 1.3.4

Vetco Vetco manufacture both a double cylinder and a single cylinder drill string compensator. In the former model, the cylinder bore is 10 3/4" and the piston rods are &, the other model has a 14" bore cylinder and a 7, piston rod. Load capacities, working and locked, are similar to the Rucker compensator. The pistons extend from the bottom of the cylinders and attach directly to the lower yoke and hook. Hydraulic pressure on the rod side of the piston supports the load - 3500 psi is the maximum operating pressure. Hydraulic lines connect the cylinders to a high pressure air/fluid accumulator mounted in the derrick. Deceleration valves are installed on both the compensator and the accumulator and will cut off the fluid supply almost instantaneously if a sudden pressure drop occurs. This could happen, for instance, if the drill string parted or a hydraulic hose burst. A mechanical locking pin locks the compensator dosed when required. The hydraulic fluid used should be very carefully chosen. It should have the correct viscosity, have a high flash point and not be toxic or corrosive. Keeping the fluid clean is one of the major problems associated with the compensator. A typical Vetco compensator installation uses six 25 cu ft vessels for high pressure air supply fed by two 15 hp compressors. The driller's control panel contains gauges to indicate air pressure in the bottles and in the compensator and also an extensiometer which shows how far open or closed the pistons are. Control handles operate the locking mechanism, the operating pressure supply and the position of the deceleration valves (close-automatic-open). The Shaffer control panel contains similar controls and gauges.

1.3.5

Western Gear This is a single cylinder model that also uses high pressure hydraulic fluid on the rod side of the piston to support the load. In order to eliminate the effects of rig motion whilst logging, a sensing line can be run from a fixed point on the rig floor, over a sheave suspended from the hook and then attached to the riser, which is fixed relative to the bottom of the hole. The compensator is pressured up so that the upward force it exerts on the hook (over which the logging cable also passes) is greater than the wireline tension. This results in the sensing line being in tension, so that the hook will then start compensating. Similarly, a sensing line with a counter-weight can be used to support a geolograph line attached to the hook frame or lower compensator yoke in order to obtain accurate ROP measurements whilst drilling with the compensator.

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DRILLING FROM A FLOATING VESSEL

1.3.6

Maritime Hydraulics Maritime Hydraulics manufacture a derrick-mounted compensator system. There are two compensator units, each with a single-acting hydraulic cylinder, an air-oil medium separator and a safety shut-off valve. These are connected at their inner ends to the crown block, which can now move up and down relative to the derrick, and at their outer ends, to an extension structure on the derrick. In the plane at right angles to the compensator units are two rocker arms. These carry sheaves for the fast and dead lines, eliminating linear motion in these lines. The compensator units are plumbed to air-spring pressure vessels, with a make-up (pump) unit to maintain the pressure therein. The system is lighter than a travelling block-mounted unit and further saves weight by reducing the total hook load rating (which includes the load due to travelling compensators and dollies). It does, however, put a dead load at the top of the derrick which has a negative effect on vessel stability. Rod seals only are used, and it is claimed that maintenance is simpler than in a travelling block-mounted unit. The moving geometry of the piston assemblies ensures a near-linear response in a vertical sensor. This is because the pressure within the compensator units increases as the crown block moves down, but the angles of the piston changes, reducing the vertical component of that force.

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Figure 10 – Rucker Drill String Compensator

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Figure 11

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1.4

TENSIONERS Tensioners operate on the same principle as the drill string compensator though force variation is not so critical, fluctuations of +/- 15% of the load being acceptable. A typical guideline tensioner has a dynamic load capacity of 16,000 lbs and allows 40 ft of wireline travel via a 4.1 mechanical advantage. This type of tensioner would also be used to support BOP control pod lines and for TV guidelines if a TV guide frame is run. The larger riser tensioner has a dynamic load capacity of 60,000 lbs or 80,000 lbs and permits 50 ft of line travel. For deep water six of the 80,000 lbs tensioners would be a typical requirement for riser support. As for the drill string compensator there are two basic designs of tensioners; produced.

1.4.1

NI- Shaffer Tensioner In this design two fixed sheaves are attached to the bottom of the cylinder and two sheaves are attached to the rod. This is maintained in compression by hydraulic oil which is pressurised by air in an accumulator. A low pressure accumulator provides oil for extension speed control and lubrication at the rod side of the piston. Full tension is achieved with 2200 psi operating pressure.

1.4.2

Vetco Tensioner In the VETCO design of tensioner the two pairs of sheaves are arranged in such a way that the rod is placed in tension and travels between the two pressure vessels which are part of the supporting structure. One of the pressure vessels contains hydraulic fluid pressurised by air. The fluid is ported to the rod side of the piston. The other pressure vessel contains only high pressure air which is used to help pressurize the fluid in the first cylinder and also in the case of the riser tensioner is ported via a valve to the top of the cylinder to act on the piston face. A deceleration device is fitted to the hydraulic line to reduce piston travel speed in case the guideline or tensioner line breaks. To obtain maximum tension 3500 psi operating pressure is needed. In each design air pressure is provided by a compressor/air bottle system operated from a control panel. Riser tensioner air lines are manifolded in opposite pairs so that an equal pull is obtained on opposite sides of the riser.

1.4.3

Maritime Hydraulics The principle of the MH tensioner is similar to the NL Shaffer tensioner. A mixture of water and glycol is used as the hydraulic fluid. The maximum operating pressure is 3000 psi and they are available in ratings from 80,000 to 120,000 Ibs; per cylinder. They are available in both single and dual units. Guideline tensioners are also manifolded in pairs or sometimes altogether. After being reeved over the tensioner a guideline is usually run to an air tugger on which it can be stored. Riser lines are damped at an anchor point. Since riser lines have a limited life they must be slipped regularly like drilling line. The most practical way to estimate the amount of work done by the line is to calculate its ton-cycles. If a heave recorder chart is available the average number of heaves over a 24 hr period can be determined, otherwise regular timings of the heave period can be taken. In either case a record of the number of cycles per day should be obtained and multiplied by the applied tension in tons.

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DRILLING FROM A FLOATING VESSEL Similar types of tensioners are also used for mooring supply vessels to a rig. Similar, but smaller tensioners are also available for guideline tensioning.

Figure 12

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1

INTRODUCTION TO PRESSURE CONTROL

1.1

WHAT IS PRESSURE? Pressure is a potential energy trapped in a fluid within a closed vessel. It can be applied by a pump or a column of fluid. Normally, pressure is measured in pounds per sq. ins. (psi). Pressure is capable of doing work as can be seen in Figure 1. A relatively low pressure of 50 psi, applied to a piston of 8 ins. Diameter, is capable of lifting a car weighing 2500 lbs (over a ton!). Very high pressure are encountered in drilling (up to 20,000 psi) and the control of these pressures therefore requires the use of very strong equipment. This section deals with the control of those pressures.

Figure 1 – The Effect of Pressure

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1.2

PRESSURES INVOLVED IN DRILLING The two main pressures involved in drilling are: · ·

1.2.1

Hydrostatic pressure Formation pressure.

Hydrostatic Pressure Hydrostatic pressure is the pressure exerted on the wellbore by the column of drilling mud. It is measured in units of pounds per square inch, psi and exerted in all directions. Hydrostatic pressure is proportional to the density of the drilling fluid and the depth in question. Density of drilling of fluid can be measured in units of: · · · ·

Pounds/gallon (US) Pounds/cubic ft. Specific gravity Psi per 1,000 ft.

Given the units of density, the gradient of the fluid can be attained in psi per foot, as follows: ppg x 0.052 pcf x 0.007 SG x 0.433

= = =

mud gradient psi/ft mud gradient psi/ft mud gradient psi/ft

Having found the mud gradient the hydrostatic pressure is found thus: Hydrostatic Pressure 1.2.2

=

depth in question x mud gradient

Formation Pressure Formation pressure is also measured in units of psi and is found thus: Formation Pressure

=

depth x formation gradient

This pressure is present in gas or fluid bearing formations and exerts an opposite force to the hydrostatic pressure. In a normal formation, i.e., one where there is communication to the surface via permeable formations, the gradient is equal to anything between 0.433 and 0.52 psi/ft but 0.465 psi/ft generally accepted as being the norm. The figure varies from area to area depending on the salinity of formation fluids, but it is generally accepted as the norm. Certain types of formations or geological traps create abnormal conditions so that there is no communication to the surface. These zones would either have abnormal gradients; i.e., more than 0.465 psi/ft, or subnormal gradients, i.e., less than 0.465 psi/ft.

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1.3

CAUSES OF A KICK A kick will occur if formation pressure exceeds hydrostatic pressure of the mud. This can occur as a result of one of the following: 1.

Insufficient mud weight.

2.

Failing to keep the hole full whilst tripping.

3.

Swabbing the hole, whilst tripping.

4.

Lost circulation.

5.

Abnormal pressure zones.

6.

Mud cut by gas causing a reduction in mud weight.

It is primarily the drillers’ responsibility to ensure that proper procedures are obtained, so that the above conditions do not occur. However, errors, more often than not, human errors, are made and the well will kick. If the will kicks, it is again the prime responsibility of the driller to notice any signs or indications at the surface that something has gone wrong, and to act on these indications accordingly. The derrickman and the well loggers also have the responsibility in this area if they, or any other member of the drill crew, spots one of these ‘ well kick indicator’, he should inform the driller immediately. The most positive sign that a kick is occurring is the well continuing to flow after the pump had been stopped. Whilst drilling, indications of a ‘kick off’ are: · ·

An increase in the rate of flow of mud from the hole. An inexplicable gain in pit volume.

These two signs can only be indicative that a kick has occurred and formation fluids are entering the bottom of the hole. Other signs which indicate the presence of an overpressured or gas bearing formation are: · · · · · ·

Gas, oil or water cut mud. Increase in flow line temp. Decrease in pump pressure. Increase in pump strokes. Increase in rate or penetration. Increase in rotary torque/decrease in rpms.

If these signs are present it is possible that the differential pressure, i.e., hydrostatic pressure less formation pressure is getting smaller and kick conditions could be developing. If the driller is not sure of these indicators he should pick up off bottom, shut down the pump and observe the well for flow. A more sophisticated method of overpressure detection whilst drilling is the ‘D’ exponent or ‘normalised penetration rate’.

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INTRODUCTION TO PRESSURE CONTROL The method involves the plotting of a ‘normalised’ curve of penetration rate against depth. The ‘normalisation’ is performed by comparison with offset wells. Any deviation from the expected line is an indication of overpressure. The problem with ‘D’ exponent is that, it is of most use in well tried areas and no valve in a rank wildcat.

1.4

BLOWOUT PREVENTION EQUIPMENT To enable a well to be kept under control when a ‘kick’ situation develops valves are fitted to the wellhead and these valves are known as Blow Out Preventers or BOPs. The BOPs are part of the equipment that is required to control a well, the other item being a kill line and a choke line from the wellhead and choke manifold. There is no basic difference in the BOPs used onshore and on a platform and there is only detail difference between those used on the surface and those used on the sea bed (when drilling from a floating rig). The principles of operation and the internals of the BOPs are the same. There are two types of BOPs; See Figure 2. · ·

Annular Ram.

The annular consists of a ring of rubber with metal inserts which when activated is forced inwards towards the centre of the ring closing around whatever is inside the ring rubber. The ram type have two separate blocks of metal, with rubber seals which when activated meet in the centre of the wellhead closing around the pipe that is in the hole. In the ram type preventers there are two types of rams: · ·

Pipe Rams Blind Rams.

The pipe rams will only fit one specific size of pipe as the rams have to be cut out-so as to fit around the pipe size in question, therefore for every size of pipe used there is a different size ram. To close on an empty hole, blind rams are used. These have no cuts outs and are made so that they will mesh into each other when closed sealing the hole completely. A variant of this type is the shear ram, which has the same function as the blind ram but also includes a scissors action which will cut through any pipe that is in the hole. The number of BOPs that are used on any hole will vary with the type of hole being drilled. Onshore the number will be three or four, consisting of one annular preventer, one pipe ram and one blind ram. If a fourth preventer is added it will also be a pipe ram. The same configuration will apply on a platform or a jack up rig. On a floating rig with a sea bed system there will be five or six BOPs, consisting of one or two annular preventers, three pipe ram Preventers and one blind/shear ram. All BOPs are worked in the same manner, by hydraulic pressure. When it is desired to shut the BOP, a valve next to the driller or at a remote position, is operated and allows hydraulic pressure to enter the BOP chamber, thus closing it. For opening, pressure is applied to the opposite side of the operating mechanism and the BOP is opened.

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Figure 2 – Blowout Preventers

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INTRODUCTION TO PRESSURE CONTROL At some stage in drilling a well there may be a time when the hydrostatic pressure of the drilling fluid is not adequate and the formation fluid will begin to flow. To prevent disastrous results from the potentially uncontrolled situation (blowout), BOPs are used. Based upon the two types of BOPs, various combinations have evolved into systems or stacks. In addition to the system or stacks there are ancillary control devices so that the well can be killed under controlled conditions. It is an unfortunate fact that basically all blowouts that occur can be directly attributed to human error and not to mechanical failure. A survey in 1971 found that out of 32 wells that blew out: 44% were whilst tripping, 41% whilst drilling, 9% circulating, and after freeing, stuck pipe, and 6% other causes. The ram type BOPs have one piston and cylinder on either side which are affixed to the ram. To close the ram, hydraulic fluid under pressure, is admitted to the cylinder. This causes the piston to move and pushes the ram against the pipe in the well. There are three makes of annular preventer, Cameron, Shaffer and Hydril, and whilst there are detail differences in the mode of operation the basic principle is the same for all three. To change the rubber in the BOP, the top of the preventer is taken off and the rubber removed and replaced. The combination of blow out preventers is known as stack; See Figure 3. In an annular preventer, hydraulic pressure is used to close a large rubber ‘doughnut’ which closes inwards around anything which is in the hole and can close completely over open hole to seal the well. Annular preventers are usually used first in a kick situation as they will close on anything in the hole (including tool joints), whereas rams will only close on a particular diameter of pipe. However, rams are capable of containing higher pressures than annulus and are therefore used once a well is shut in. The hydraulic fluid for actuating a BOP system is kept in accumulators, which are pressure vessels containing nitrogen and hydraulic fluid. The hydraulic fluid is pumped into the accumulator until the required pressure is reached. An automatic pump is used to maintain accumulator pressure. On opening the valve to actuate the BOP, the nitrogen expands forcing the fluid to operate the BOP. It is normal to have the accumulator system designed to have sufficient capacity to safely control a kick should a power failure occur. All BOPs are designed so that when they are used, the well pressure coming up under the BOP will assist in closing the BOP so that if the hydraulic pressure fails there will be no chance of the BOP opening. The control panels for the BOPs will be by the drillers position and there will be remote panels away from the rig so that the BOPs can be closed even if the rig has had to be evacuated. Once the kick has been contained by the use of the BOPs, other equipment; See Figure 5, is required to control the annulus pressure and circulate the influx out of the hole. The choke manifold consists of a remote control choke, which can be controlled from the drillers position, a hand operated adjustable choke, and fixed chokes. By adjusting these chokes, it is possible to control the back pressure in the annulus. The remote control adjustable choke enables the driller to hold the desired pressure on the annulus whilst controlling pumping rate, etc. Fixed chokes can be used if the rate at which the fluid is coming out of the well is too great for the adjustable choke, in which case, the fixed choke is used in parallel with the adjustable choke. The control panel for the choke incorporates a control handle and two pressure gauges to measure drill pipe pressures and annulus pressure. This panel is normally situated next to the BOP control panel to allow complete control of the kicking well from one location. 6

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Figure 3 – BOP Stack

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Figure 4 – Subsea BOP Stack

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Figure 5 – Well Control Equipment

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1.5

PREPARATION FOR A KICK Although we may have a reasonable idea of the formation pressure and have weighted our mud accordingly, we can never be certain of the exact formation pressure whilst drilling. For this reason, everyone involved in the drilling operation is constantly on the watch for signs of a kick. The importance of early detection cannot be over-emphasised. Everybody involved should be encouraged to report anything which they consider to be a possible kick indicator. It is better to have ten false alarms than it is to take a large kick. Each day, several people on the rig will be performing calculations and taking readings so that they are prepared should a kick occur.

1.5.1

Kick Sheets At regular intervals throughout the well, the drilling engineer (or Company man) and the driller (or Toolpusher) will fill in a kick sheet; See Figure 6, Figure 7 and Figure 8. All the current information pertaining to the well is written on this sheet so that in the event of a kick, all the information is readily at hand and calculations can be performed quickly. This cuts down the amount of crucial calculations to be performed in the tense conditions of a kick situation. A new kick sheet is completed each time there is a change to the well, e.g. change in mud weight, setting casing and at regular intervals (perhaps every 100 ft) during the drilling phase.

1.5.2

Maximum Allowable Annular Surface Pressure (MAASP) MAASP is the maximum pressure which can be applied to the annulus at surface without fracturing the formation at the casing shoe. The MAASP calculation is performed every time there is a change in mud weight. During circulation of a kick, the value of MAASP is always in mind when looking at the reading on the casing pressure gauge. However, under no circumstances should casing pressure be bled off if it exceeds MAASP; this would lead to a further influx at the bottom of the hole. There are several courses of action which can be taken in the case of the casing pressure approaching MAASP; one course is to ‘reverse circulate’ the kick from the well. This involves circulating the kick down the annulus and up the drill pipe. Another course of action is to ‘bullhead’ the kick back to formation. These are specialist techniques and their details will not be mentioned here. It should be noted that in most cases, provided the casing design has given sufficient consideration to kick size, the casing pressure will not exceed the MAASP during circulation of a kick. It is only in the situation where the kick is of a pressure exceeding that of the ‘design kick’ or where the volume exceeds that allowed for in the design that problems with MAASP will be encountered.

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Figure 6 – Kick Data Sheet 1

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Figure 7 – Kick Data Sheet 2

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Figure 8 – Kick Data Sheet 3

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1.5.3

Slow Circulating Rates (SCRs) For both the ‘drillers’ method and the ‘wait and weight’ method, the pump pressure at various slow circulating rates – SCRs is required. This allows us to calculate the pump pressure required to kill the well. Normally, during drilling, SCRs are taken every 12 hours; at the beginning of each shift. However, if drilling is rapid, they may be taken every 100 ft of new hole. They will also be taken each time there is a change in BHA or mud properties. All that is required is to run the pump, with the bit just off bottom, at various rates, and measure the pressures. Example:

14

PUMP RATE

PUMP PRESSURE

(Strokes per Minute)

(psi)

20 spm

400

30 spm

430

40 spm

480

50 spm

520

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1.6

ACTION IN THE EVENT OF A KICK The most important aspect of kick control is to be able to take the correct action at the earliest possible moment, as the longer the kick is allowed to go without being controlled the more likely it is that the situation will become uncontrollable. The first and most important factor is the early recognition of the kick, and assuming that a kick has been detected the steps that are taken should be: · Stop the pump · Pull the Kelly clear of the rotary table · Ensure that a choke (usually the remote adjustable) is fully closed · Close the annular Blow Out Preventer · Observe the drill pip an annulus pressures (until pressures are stabilised). There will be many variations on these procedures depending on rigs, equipment and the particular operation being performed. (e.g. drilling, tripping, etc.) Once the situation is under control and the basic steps have taken it is then possible to calculate the position of the tool joints, and if the pipe rams are to be closed on the drill pipe then the pipe rams should be closed and the annular preventer opened. The use of the annular preventer in the first instance is to ensure that a shut off is achieved at the earliest possible moment without having to waste time calculating the position of tool joints relative to the rams. Once shut in is achieved and the position of the tool joints is known, the string can be ‘stripped’ into the hole through the annular without re-opening the well.

1.6.1

Kick Control We have seen how the driller recognises the kick, we have looked at his equipment and the immediate action he took on detecting the kick. The well should now be shut in and as such, the pressures are in a state of equilibrium. That is, the formation pressure is balanced by the hydrostatic pressures plus shut in pressures. Having determined the kill mud weight, it is necessary to circulate this mud around the system and to expel the old mud and invading fluid. Whilst doing this we must be careful not to allow a secondary kick into the system, and we must be equally careful not to burst the system, which is in reality a large pressure vessel. If a burst occurs it is likely to be at the formation below the last casing shoe, this usually being the weakest point. For this reason, figures should always be available on the maximum pressure, this part of the system cam hold (MAASP). So, whilst circulating out an influx we must hold a constant bottom hole pressure, perhaps a little greater than the formation pressure, but certainly no less. Whilst circulating, this bottom hole pressure will be made up of: · Back pressure at the choke · Hydrostatic pressure of mud · Hydrostatic pressure of influx · Circulating losses in the annulus. The hydrostatic pressure will probably change during circulation especially if the influx is gas, so back pressure at the choke will be used to make up for any loss in hydrostatic pressure.

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INTRODUCTION TO PRESSURE CONTROL Control is maintained in the first place by monitoring the drill pipe or casing pressure and keeping constant pump strokes, any variations in pressures on these gauges can be altered by manipulating the choke. There are three methods of circulating the kill mud: 1.

Wait and Weight Method

2.

Drillers Method

3.

Concurrent Method.

Of these three methods the wait and weight method is the most effective, and favoured by the majority of operators. We will discuss the ‘wait and weight’ and ‘drillers method’. 1.6.2

Wait and Weight Method See Figure 9 and Figure 10. In this method, once the well has been shut in and the pressures have stabilised, the kill mud weight is calculated. We then wait whilst kill mud is ‘weighted up’ in the mud pit; hence the name ‘wait and weight’. Once the mud has been weighted up, pumping commences and constant bottom hole pressure is maintained throughout by use of the choke. The advantage of this method is that it requires only one circulation to kill the well. The waiting period whilst mud is weighted up also allows time to organise the crew and consider the problem thoroughly. Furthermore, the method results in the minimum pressures at surface and at the casing shoe because kill weight mud is used immediately. Conversely, the method is more complicated and requires more arithmetic – with well trained crews this should not be a problem.

1.6.3

Drillers Method See Figure 11, Figure 12 and Figure 13. This method is more simple than the wait and weight method. performed here.

Two circulation’s are

In the first circulation, original mud is circulated to bring the flux from the well. Bottom hole pressure is kept constant by means of the choke and thus no further influx is permitted. Once the influx has been removed from the well, a second circulation is carried out with the kill weight mud. The advantage of this method is that circulation can commence immediately whilst weighing up a second pit to kill weight mud. However, the pressures which result from this method at the surface and at the shoe are higher than in the wait and weight method and the method is therefore not so popular.

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INTRODUCTION TO PRESSURE CONTROL

Figure 9 – The Wait and Weight Method

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INTRODUCTION TO PRESSURE CONTROL

Figure 10 – Pressure Profile by Wait & Weight

18

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INTRODUCTION TO PRESSURE CONTROL

Figure 11 – The Drillers Method

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INTRODUCTION TO PRESSURE CONTROL

Figure 12 – Drillers Method 1st Circulation

20

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INTRODUCTION TO PRESSURE CONTROL

Figure 13 – Drillers Method 2nd Circulation

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INTRODUCTION TO PRESSURE CONTROL

1.7

WELL CONTROL EXAMPLE

1.7.1

Well Data Depth 12,000 ft Original mud weight 10 PPG Casing size 10¾”, J55, 40.5 lb/ft Shoe depth 6,000 ft Drill pipe 4½” x 16.6 lb/ft Drill collars 1,000 ft x 8” x3” Pump output at 30 SPM 5.82 BBL/min Casing min. burst 3130 psi, at 80%, 500 psi Formation breakdown pressure = 4,560 psi i.e. fracture gradient = 0.76 psi/ft

1.7.2

Capacities Drill pipe Drill collars 10¾” Csg x 4½” DP annulus 10” hole x 4½” DP annulus 10” hole x 8” DC annulus

1.7.3

Kick Data To be read on simulator: Closed in drill pipe pressure Closed in casing or annulus pressure Pit volume gain

22

0.0142 BBL/ft 0.0087 BBL/ft 0.0784 BBL/ft 0.0774 BBL/ft 0.0394 BBL/ft

600 psi 920 psi 30 BBLS

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INTRODUCTION TO PRESSURE CONTROL

1.8

PRESSURE CONTROL - EXERCISE 1.

In a hole formation pressure (Pf) at 3,000 ft is 1,800 psi. At 4,000 ft Pf is 2,000 psi. a) b)

2.

What is the minimum mud weight we can use to drill both of the formations? What would be the mud weight required if we wanted a 200 psi overbalance?

In the same hole as question 1. The formation breakdown pressure (Pfb) at 3,000 ft is 2,400 psi and at 4,000 ft Pfb is 3,000 psi. What is the maximum mud weight that can be used to drill both formations?

3.

With casing set at 3,000 ft a leak off test is carried out after drilling out the shoe plus 20 ft of new formation. With 1.15 SG mud in the hole a leak off of 600 psi was established. a) b)

4.

What is the formation strength in psi? What is the maximum allowable mud weight in ppg?

I a hole with casing set at 3,000 ft the formation strength i.e. breakdown pressure at the shoe is established at 2,220 psi. With 1.2 SG mud in the hoe: a) What would have been the pressure at surface from a leak off test? b) What is the formation breakdown gradient? c) What is the maximum mud weight permitted?

5.

With 95/8” casing shoe at 10,000 ft the formation breakdown gradient at the shoe is determined as 0.87 psi/ft. Using 13 PPG mud: a) b) c)

ã DTL 2001 – Rev 2

What is the formation breakdown pressure at the shoe? What is MAASP? What is the new MAASP if mud weight is increased to 14 PPG?

23

INTRODUCTION TO PRESSURE CONTROL

24

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GLOSSARY

1

GLOSSARY

1.1

LIST OF ABBREVIATIONS HMUD

=

Head of Mud or Hydrostatic Pressure of Mud (usually psi).

GMUD

=

Pressure gradient of mud (usually psi/foot).

PF

=

Formation (Fluid) Pressure (usually psi).

PFB

=

Formation Breakdown Pressure or Formation Fracture Pressure or Formation Strength (usually psi).

GFB

=

Formation Breakdown Pressure Gradient (usually psi/foot).

MAX EMW

=

Maximum Equivalent Mud Weight, to produce Formation Breakdown Pressure at Shoe.

MAASP

=

Maximum Allowable Annular Surface Pressure (usually psi). Surface Pressure, which if exceeded may cause leakage of whole mud into formation of the casing shoe.

SIDPP

=

Shut in Drill Pipe Pressure (usually psi).

SICP

=

Shut in Casing Pressure (usually psi).

ICP

=

Initial Circulating Pressure (usually psi).

FCP

=

Final Circulating Pressure (usually psi).

SCRP

=

Slow Circulating Rate Pressure or Kill Rate Pressure, sometimes written PSCR (usually psi).

BHP

=

Bottom Hole Pressure, the pressure exerted within the hole by mud head and surface applied pressures (usually psi).

PLO

=

Leak Off Pressure (usually psi).

APL

=

Annulus Pressure Loss (usually psi).

ECD

=

Equivalent Circulating Density or Equivalent Circulating Mud Weight (usually ppg).

PPG

=

Pounds per U.S. Gallon sometimes written lb/US gal.

MW

=

Mud Weight (usually ppg).

KMW

=

Kill Mud Weight (usually ppg).

OMW

=

Original Mud Weight (usually ppg).

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1

GLOSSARY

1.2

WELL CONTROL FORMULAE (API AND COMMON UNITS) HYDROSTATIC PRESSURE Hydrostatic Pressure = ppg x 0.052 x Depth, (True vertical) (psi) (ft) Hydrostatic Pressure = SG x 0.433 x Depth, (True vertical) (psi) (ft) PRESSURE GRADIENT psi/foot = ppg x 0.052 psi/foot = SG x 0.433 CIRCULATING BOTTOM HOLE PRESSURE Circulating BHP = Static BHP + Annulus Pressure Loss (psi) (psi) (psi) EQUIVALENT CIRCULATING DENSITY Annulus Pressure Loss ECD = Static Mud Weight + (ppg) Depth (True Vertical) x 0.052

FORMATION BREAKDOWN PRESSURE PFB = Leak-off Pressure + Static Pressure of Mud to Shoe (psi)

Note ‘Static Pressure of Mud’ is often written as ‘Head of Mud’.

FORMATION BREAKDOWN GRADIENT GradientFB PFB = (psi/ft) Shoe Depth (True Vertical)

MAXIMUM EQUIVALENT MUD WEIGHT Max. Equiv. Mud Weight = (ppg)

PFB Shoe Depth (True Vertical) x 0.052

MAXIMUM ALLOWABLE ANNULAR SURFACE PRESSURE MAASP = PFB – Head of Mud to Shoe (psi) MAASP = GFB – GMUD x Shoe Depth (True vertical) (psi) MAASP = (Max Equiv.Mud wt – Current Mud wt) x Shoe Depth x 0.052 (psi) (True vertical)

2

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GLOSSARY

KILL MUD WEIGHT Kill Mud Weight Original Mud Weight SIDPP = + (ppg) (ppg) Depth, (True Vertical) x 0.052

or Formation Pressure Kill Mud Weight = (ppg) Depth (True Vertical) x 0.052

INITIAL CIRCULATING PRESSURE ICP = Slow Circulating Rate Pressure + SIDPP (psi) FINAL CIRCULATING PRESSURE Kill Mud WT FCP = Slow Circulating Rate Pressure x (psi) Orig. Mud WT

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3

GLOSSARY

1.3

WELL CONTROL FORMULAE (SI) HYDROSTATIC PRESSURE Hydrostatic Pressure = Mud Weight ¸ 102 x Depth (True vertical) (Kpa) (Kg/m3) (Metres) PRESSURE GRADIENT KPa/Metre = Kg/m3 ¸ 102 CIRCULATING BOTTOM HOLE PRESSURE Circulating BHP = Static BHP + Annular Pressure Loss (Kpa) (Kpa) (Kpa) EQUIVALENT CIRCULATING DENSITY Static Mud WT Annular Pressure Loss (Kpa) x 102 ECD = + 3 (kg/m ) (kg/m3 ) Depth (True Vertical)(Metres)

MAXIMUM ALLOWABLE ANNULAR SURFACE PRESSURE MAASP PFB H = - MUD (KPa) (KPa) (KPa)

or MAASP (G FB - G MUD ) Shoe Depth, (True Vertical) x = (KPa) (KPa/m) (KPa/m) (Metres)

or MAASP = (KPa)

Max Equiv. Mud WT - Current Mud WT ¸ 102 x Shoe Depth (True Vertical) (Kg/m3 ) (Kg/m3 ) (Metres)

KILL MUD WEIGHT Kill Mud WT Original Mud WT SIDPP (KPa) x 102 = + 3 3 (Kg/m ) (Kg/m ) Depth (True Vertical)(Metres)

INITIAL CIRCULATING PRESSURE ICP SCRP SIDPP = + (KPa) (KPa) (KPa)

FINAL CIRCULATING PRESSURE FCP = (KPa) 4

SCRP x Kill Mud WT (Kg/m3 ) (KPa) Old Mud WT (Kg/m3 ) ã DTL 2001 – Rev 2

GLOSSARY

1.4

APPROPRIATE CONVERSIONS DEPTH Feet Metres

x 0.3048 to give Metres (m) x 3.2808 to give Feet (ft)

VOLUME (U.S) Gallon (U.S) Barrel Cubic Metre

x 0.003785 to give Cubic Metres (m3) x 0.1590 to give Cubic Metres (m3) x 6.2905 to give Barrel (U.S)

PRESSURE PSI KPA Kg/cm2 Bar

x 6.895 to give Kilo Pascals (Kpa) x 0.14503 to give pounds per square inch (psi) x 98.1 to give Kilo Pascals (Kpa) x 100 to give Kilo Pascals (Kpa)

MUD WEIGHT PPG Kg/m3

x 119.8 to give Kilogram per Cubic Metre (Kg/m3) x 0.00835 to give (Pounds per Gallon)

PRESSURE GRADIENT PSI/Foot x 22.62 to give Kilo Pascals per Metre (KPa/m) KPa/Metre x 0.04421 to give Pounds per Square Inch per Foot (psi/ft) MUD WEIGHT TO PRESSURE GRADIENT PPG x 0.052 to give Pounds per Square Inch per Foot (psi/ft) [Pressure Gradient] SG x 0.433 to give Pounds per Square Inch per Foot (psi/ft) 3 lb/ft ¸ 144 to give Pounds per Square Inch per Foot (psi/ft) Kg/m3 x 0.000434 to give Pounds per Square Inch or ¸ 2303 per Foot (psi/ft) 3 Kg/m x 0.00982 to give Kilo Pascals per Metre (KPa/m) FLOW RATE Gallons/Minute Barrels/Minute Cubic Metres/Minute Cubic Metres/Minute

x 0.003785 x 0.159 x 6.2905 x 264.2

ANNULAR VELOCITY Feet/Minute x 0.3048 Metres/Minute x 3.2808

ã DTL 2001 – Rev 2

to give Cubic Metres per Minute (m3/min) to give Cubic Metres per Minute (m3/min) to give Barrels per Minute (bbl/min) to give Gallons per Minute (gals/min) to give Metres per Minute (m/min) to give Feet per Minute (ft/min)

5

GLOSSARY

FORCE (e.g. WEIGHT ON BIT) Pound Force x 0.445 to give Decanewtons Decanewtons x 2.2472 to give Pound Force MASS Pounds

x 0.454 Tons (Long 2240 lbs) x 1017 Tonnes (Metre 2205 lbs) x 1001 Kilograms x 2.2026

PIPE WEIGHTS Pound/Foot Kilogram/Metre

6

x 1.49 x 0.671

to give Kilograms (kg) to give Kilograms (kg) to give Kilograms (kg) to give Pounds (lbs) to give Kilogramme/Metre to give Pound/Foot

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GLOSSARY

1.5

OTHER USEFUL FORMULAE APPROXIMATE GAS PRESSURE & VOLUME RELATION Pressure1 x Volume1 = Pressure2 Volume2 (any units)

NOTE:

This disregards Temperature and Gas Compressibility Factor; allowing for temperature gives:

P1 x V1 T1

=

P2 x V2 T2

P = Pressure V = Volume T = Temperature, degrees Absolute

APPROXIMATE RELATION BETWEEN PUMP PRESSURE AND PUMP RATE æ New Pump Rate ö ÷÷ New Pump Pressure = Old Pump Pressure x çç è Old Pump Rate ø

2

WEIGHT OF BARITE REQUIRED FOR MUD WEIGHT INCREASE

Pounds of Barite Required 1490 (Final Mud WT - Original Mud WT) = per bbl of Mud 35.5 - Final Mud WT (Mud Weights in ppg) VOLUME INCREASE DUE TO BARITE ADDITION

Volume Increase =

Final Mud WT - Original Mud WT 35.5 - Final Mud WT (Mud Weights in ppg)

HYDROSTATIC PRESSURE EXERTED BY MUD IN ANNULUS

Hydrostatic Pressure per Barrel (psi)

ã DTL 2001 – Rev 2

=

Mud Weight x 0.052 Annular Volume

7

GLOSSARY

8

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GLOSSARY

A GLOSSARY OF PETROLEUM TERMS abandon v: to cease producing oil and gas from a well when it becomes unprofitable. a wildcat well may be abandoned after it has proven nonproductive. Several steps are involved in abandoning a well: part of the casing may be removed and salvaged; one or more cement plugs placed in the borehole to prevent migration of fluids between the different formations penetrated by the borehole. In many countries it is necessary to secure permission form official agencies before a well may be abandoned. abnormal pressure n: pressure exceeding or falling below the normal pressure to be expected at a given depth. Normal pressure increases approximately 0.465 psi per foot of depth (10.5 kPa per metre of depth). Thus, normal pressure at 10,000 feet is 4,650 psi.; abnormal pressure at this depth would be higher or lower than 4,650 psi. See pressure gradient. absolute permeability n: a measure of the ability of a single fluid (such as water, gas, or oil) to flow through a rock formation when the formation is totally filled (saturated) with the single fluid. The permeability measure of the same rock filled with two or more fluids. Compare effective permeability. absolute porosity n: percentage of the total bulk volume of a rock sample that is composed of pore spaces or voids. See porosity. absolute pressure n: total pressure measured from an absolute vacuum. It equals the sum of the gauge pressure and the atmospheric pressure corresponding to the barometer (expressed in pound per square inch). absolute temperature scale n: a scale temperature measurement in which zero degrees is absolute zero. On the Rankine absolute temperature scale, in which degrees correspond to degrees Fahrenheit, water freezes at 492 degrees and boils at 672 degrees. On the Kelvin absolute temperature scale, in which degrees correspond to degrees Celsius, water freezes at 273 degrees and boils at 373 degrees. See absolute zero. absolute zero n: a hypothetical temperature at which there is a total absence of heat. Since heat is a result of energy caused by molecular motion, there is no motion of molecules with respect to each other at absolute zero. acceptance criteria n: defined limits placed on characteristics of materials, products, or services. (API Specification 16A) accumulate v: to amass or collect. When oil and gas migrate into porus formations, the quantity collected is called an accumulation. accumulator n: 1. A vessel or tank that receives and temporarily stores a liquid used in a continuous process in a gas plant. N: 2. On a drilling rig, the storage device for nitrogen-pressurised hydraulic fluid, which is used in closing the Blowout Preventers. See Blowout Preventer control unit. accumulator bank n: an assemblage of multiple accumulators sharing a common manifold. (API Recommended Practice 16E) accumulator precharge n: an initial nitrogen charge in an accumulator which is further compressed when the hydraulic fluid is pumped into the accumulator storing potential energy. (API Recommended Practice 16E) acidity n: the quality of being an acid. Relative acid strength of a liquid is measured by pH. a liquid with a pH below 7 is an acid. See pH value

ã DTL 2001 – Rev 2

acoustic control system n: a subsea control system that uses coded acoustic signals communication. An acoustic control system is normally used as an emergency backup, having control of a few selected critical functions. (API Recommended Practice 16E) actuation test, Blowout Preventer n: the closing and opening of a Blowout Preventer unit to assure mechanical functionality. (API Recommended Practice 57). actuator n: a device used to open or close a valve by means of applied manual, hydraulic, pneumatic or electrical energy. (API Recommended Practice 64) adapter n: a pressure containing piece of equipment having API end connections of different nominal sizes and/or pressure ratings, used to connect other pieces of equipment of different API nominal sizes and/or pressure ratings. (API Specification 16A) adapter spool n: a joint to connect Blowout Preventers of different sizes or pressure ratings to the casing head. adjustable choke n: a choke in which the position of a conical needle or sleeve may be changed with respect to its sea, to vary the rate of flow; may be manual or automatic. See choke aerated fluid n: drilling fluid injected with air or gas in varying amounts for the purpose of reducing hydrostatic head. (API Recommended Practice 64). air-actuated adj.: powered by compressed air, for example, the clutch and the brake system in drilling equipment. air drilling n: a method of rotary drilling that uses compressed air as the circulation medium. The conventional method of removing cuttings from the well bore is to use a flow of water or drilling fluid. Compressed air removes the cuttings with equal or greater efficiency. The rate of penetration is usually increased considerably when air drilling is used. A principal problem in air drilling, however, is the penetration of formations containing water, since the entry of water into the systems reduces the ability of the air to remove the cuttings. air gap n: the distance from the normal level of the sea surface to the bottom of the hull or base of an offshore drilling platform. air/gas drilling v: refer to aerated fluid air pump/air powered pump n: air driven hydraulic piston pump. (API Recommended Practice 16E) alkali n: a substance having marked basic (alkaline) properties, such as a hydroxide of an alkali metal. See base. alkalinity n: the combining power of a base, or alkali as measured by the number of equivalents of an acid with which it reacts to form a salt. Measured by pH alkalinity is possessed by any solution that has a pH greater than 7. See pH value. American Petroleum Institute n: founded in 1920, this national oil trade organisation is the leading standardising organisation for oil field drilling and producing equipment. It maintains departments of transportation, refining, and marketing in Washington, DC, and a department of production in Dallas. Adj.: (slang) indicative of a job being properly or thoroughly done (as, "His work is strictly API").

9

GLOSSARY

American Society for Testing and Materials n: an organisation, based in Philadelphia, which sets guidelines for testing ad use of equipment and materials. American Society of Mechanical Engineers n: a New York City-based organisation whose equipment standard are sometimes used by the oil industry. Its official publication is Mechanical Engineering. anchor n: any device that secures or fastens equipment. In down hole equipment, the term often refers to the tail pipe. In offshore drilling, floating drilling vessels are often secured over drill sites by large metal anchors like those used on ships. anchor buoy n: a floating marker used in a spread mooring system to position each anchor of a semi-submersible rig or drill ship.

API gravity n: the measure of the density or gravity of liquid petroleum products, derived from specific gravity in accordance with the following equation: API gravity is expressed in degrees, a specific gravity of 10 being equivalent to 10° API.

API gravity

=

141.5 specific gravity

-

131.5

artificial lift n: any method used to raise oil to the surface through a well after reservoir pressure has declined to the point at which the well no longer produces by means of natural energy. Sucker rod pumps, gas lifts, hydraulic pumps, and submersible electric pumps are the most common forms of artificial lift.

angle of deflection n: in directional drilling, the angle, expressed in degrees, at which a well is deflected from the vertical by a whipstock or other deflecting tool.

ASME abbr.: American Society of Mechanical Engineers.

angle of deviation n: also called drift angle and angle of drift. See deviation.

astern adv. or adj.: 1. At or toward the stern of a ship or an offshore drilling rig; abaft. 2. Behind the ship or fig.

annular blowout preventer n: a large valve with a generally thyroidal shaped steel reinforced elastomer packing element that is hydraulic operated to close and seal around any drill pipe size or to provide full closure of the well bore. Usually installed above the ram preventers, it forms a seal in the annular space between the pipe and the well bore, or, if no pipe is present, on the well bore itself. annular packing element n: a rubber/steel torus that effects a seal in an annular preventer or diverter. The annular packing element is displaced toward the bore centre by the upward movement of an annular piston. (API Recommended practice 64) annular sealing device n: generally, a torus shaped steel housing containing an annular packing element which facilitates closure of the annulus by constricting to seal on the pipe or Kelly in the well bore. Some annular sealing devices also facilitate shutoff of the open hole. (API Recommended Practice 64) annular space n: 1. The space surrounding a cylindrical object within a cylinder. 2. The space around a pipe in a well bore, the outer wall of which may be the wall of either the borehole or the casing; sometimes termed the annulus. annular velocity n: the rate at which fluid is travelling in the annular space of a drilling well. annulus n: also called annular space. See annular space. annulus friction pressure n: circulating pressure loss inherent in the annulus between the drill string and casing or open hole. anticline n: an arched, inverted-trough configuration of folded and stratified rock layers. anticlinal trap n: a hydrocarbon trap in which petroleum accumulates in the top of an anticline. See anticline. API abbr.: American Petroleum Institute.

ASTM abbr.: American Society for Testing and Materials. Atm abbr.: atmosphere. atmosphere n: a unit of pressure equal to the atmospheric pressure at sea level, 14.7 pounds per square inch (101.325 kPa). One Atmosphere is equal to 14.7 psi or 101.325 kPa. atmosphere absolute n. pl.: total pressure at a depth underwater, expressed as multiples of normal atmospheric pressure. atmospheric pressure n: the pressure exerted by the weight of the atmosphere. At sea level, the pressure is approximately 14.7 psi (101.325 kPa), often referred to as 1 atmosphere. attapulgite n: a fibrous clay mineral that is viscosity-building substance, used principally in saltwater-base drilling fluids. automatic choke n: an adjustable choke that is power-operated to control pressure or flow. See adjustable choke. automatic control n: a device that regulates various factors (such as flow rate, pressure, or temperature) of a system without supervision or operation by personnel. See instrumentation. automatic driller n: a mechanism used to regulate the amount of weight on the bit without requiring attendance by personnel. Automatic Drillers free the driller from the sometimes tedious task of manipulating the draw-works brake in order to maintain correct weight on the bit. Also called an automatic drilling control unit. automatic fill-up shoe n: a device that is installed on the first joint of casing and that automatically regulates the amount of fluid in the casing. The valve in this shoe keeps fluid from entering the casing until fluid pressure causes the valve to open, allowing fluid to enter the casing. automatic gauge n: an instrument installed on the outside of a tank to permit observation of the depth of the liquid inside.

10

ã DTL 2001 – Rev 2

GLOSSARY

automatic slips n: a device, operated by air or hydraulic fluid, that fits into the opening in the rotary table when the drill stem must be suspended in the well bore (as when a connection or trip is being made). Automatic slips, also called power slips, eliminate the need for roughneck's to set and take out slips manually. See slips. auxiliary brake n: a braking mechanism, supplemental to the mechanical brake, that permits the safe lowering of heavy hook loads at retarded rates, without incurring appreciable brake maintenance. There are two types of auxiliary brakes - the hydrodynamic and the electrodynamic. In both types, work is converted in to heat which is dissipated through liquid cooling systems. azimuth n: 1. In directional drilling, the direction of the face of the deviation tool with respect to magnet north, as recorded by a deviation instrument. 2. An arc of the horizon measure between a fixed point (such as true north) and the vertical circle passing through the centre of an object. back off v: to unscrew one threaded piece (such as a section of pipe) from another. back-off joint n: a section of pipe with left-hand threads on one end and conventional right-hand threads on the other. In setting a liner, a backoff joint is attached to it so that the drill pipe may be disengaged from the liner by conventional right-hand rotation. back-pressure n: 1. The pressure maintained on equipment or systems through which a fluid flows. 2. In reference to engines, a term used to describe the resistance to the flow of exhaust gas through the exhaust pipe. back pressure valve n: a valve that permits flow in only one direction (API Recommended Practice 57) backup tongs n: the tongs used to back up the drill pipe as it is being made up into or taken out of the drill system. baffle plate n: 1. A partial restriction, generally a plate, placed to change the direction, guide the flow, or promote mixing within the tank or vessel. 2. A device that is seated on the bit pin, in a tool joint, or in a drill pipe float, used to centralise the lower end of a go-devil while permitting the bypass of drilling fluid. The go-devil while permitting the bypass of drilling fluid. The go-devil contains a surveying instrument. bail n: a cylindrical steel bar (similar in form to the handle or bail of a bucket, but much larger) that supports the swivel and connects it to the hook. Sometimes, the two cylindrical bars that support the elevators and attach them to the hook are also called bails or links. v: to recover bottomhole fluids, samples, fluid, sand, or drill cuttings by lowering a cylindrical vessel called a bailer to the bottom of a well, filling it, and retrieving it.

barite n: barium Sulphate, BaSO4; a mineral frequently used to increase the weight or density of drilling fluid. Its specific gravity or relative density is 4.2 (i.e. it is 4.2 times heavier or denser than water. See barium Sulphate and fluid. barite plug n: a settled volume of barite particles from a barite slurry placed in the well bore to seal off a pressurised zone. (API Recommended Practice 59) barium sulphate n: a chemical compound of barium, Sulphur, and oxygen (BaSO4. It may form a tenacious scale that is very difficult to remove. Also called barite. barrel n: a measure of volume of petroleum products in the United States. One barrel is the equivalent of 42 US gallons or 0.15899 cubic metres. One cubic metre equals 6.2897 barrels. barrels per day n: in the United States, a measure of the rate of flow of a well; the total amount of oil and other fluids produced or processed per day. baryte n: variation of barite. See barite. base n: a substance capable of reacting with an acid to form a salt. A typical base is sodium hydroxide (caustic), with the chemical formula NaOH. For example, sodium hydroxide combines with hydrochloric acid to form sodium chloride (a salt) and water; this reaction is written chemically as NaOH + HCl ® NaCl + H20 basement rock n: either igneous or metamorphic rock, seldom containing petroleum. Ordinarily it lies below sedimentary rock. When it is encountered in drilling, the well is usually abandoned. basin n: a cylindrical structure in the subsurface, formerly the bed of an ancient sea. Because it is composed of sedimentary rock and because its contours provide traps for petroleum, a basin is a good prospect for exploration. For example, the Permian Basin in West Texas is a major oil producer. battery n: 1. An installation of identical or nearly identical pieces of equipment (such as a tank battery or a battery of meters). 2. An electricity storage device. bbl abbr.: barrel bbl/d abbr.: barrels per day. Bcf abbr.: billion cubic feet. Bcf/d abbr.: billion cubic feet per day

bailer n: a long cylindrical container, fitted with a valve at its lower end, used to remove water, sand, fluid, drill cuttings, or oil from a well. ball valve n: a valve which employs a rotating ball to open or close the flow passage. (API Recommended Practice 64) barge n: any one of many types of flat-decked, shallow-draft vessels, usually towed by a boat. A complete drilling rig may be assembled on a drilling barge, which usually is submersible; that is, it has a submersible hull or base that is flooded with water at the drilling site. Drilling equipment and crew quarters are mounted on a superstructure above the water level.

ã DTL 2001 – Rev 2

b/d abbr.: barrels per day; often used in drilling report. B/D abbr.: barrels per day. bed n: a specific layer of earth or rock, presenting a contrast to other layers of different material lying above, below, or adjacent to it. bedding plane n: the surface that separates each successive layer of a stratified rock from its preceding layer. belching v: a slang term to denote flowing by heads (API Recommended Practice 59).

11

GLOSSARY

bell nipple n: a short length of pipe (a nipple) installed on top of the Blowout Preventer. The top end of the nipple is expanded, or belled, to guide drill tools into the hole and usually has side connections for the fill line and fluid line. bent housing n: a special housing for the positive displacement down hole fluid motor that is manufactured with a bend of 1-3 degrees to facilitate directional drilling. bentonite n: a colloidal clay, composed primarily of montmorillonite, that swells when wet. Because of its gel-forming properties, bentonite is a major component of drilling fluids. See gel. bent sub n: a short cylindrical device installed in the drill stem between the bottom most drill collar and a down hole fluid motor. The purpose of the bent stub is to defect the fluid motor off vertical to drill a directional hole. BFPH abbr.: barrels of fluid per hour; used in drilling reports. BHA abbr.: bottom hole assembly. BHP abbr.: bottom hole pressure.

blind ram preventer n: a Blowout Preventer in which blind rams are the closing elements. blind/shear rams n: blind rams with a built-in cutting edge that will shear tubulars that may be in the hole, thus allowing the blind rams to seal the hole. Used primarily in subsea systems. (API Recommended Practice 53) block n: any assembly of pulleys, a common framework; in mechanics, one or more pulleys, or sheaves, mounted to rotate on a common axis. The crown block is an assembly of sheaves mounted on beams at the top of the derrick. The drilling line is reeved over the sheaves of the crown block alternately with the sheaves of the travelling block, which is raised and lowered in the derrick by the drilling line. When elevators are attached to a hook on the travelling block and drill pipe latched in the elevators, the pipe can be raised or lowered. block position n: the centre position of a three-position control valve. (API Recommended Practice 16E) blooey line n: the discharge pipe from a well being drilled by air drilling. The blooey line is used to conduct the air gas used for circulation away from the rig to reduce the fire hazard as well as to transport the cuttings a suitable distance from the well. See formation pressure and kick.

BHT abbr.: bottom hole temperature. bit n: the cutting of boring element used in drilling oil and gas wells. The bit consists of a cutting element and a circulating element. The circulating element permits the passage of drilling fluid and utilises the hydraulic force of the fluid to improve drilling rates. In rotary drilling ,several drill collars are joined to the bottom end of the drill pipe column, and the bit is attached to the end of the string of drill collars. Most bits used in rotary drilling are roller cone bits, but diamond bits are also used extensively. See roller cone bit and diamond bit. bit breaker n: a heavy plate that fits in the rotary table and holds the drill bit while it is being made up in, or broken out of, the drill stem. See bit. bit gauge n: a circular ring used to determine whether a bit is of the correct outside diameter. Bit gauges are often used to determine whether the bit has been worn down to a diameter smaller than specifications allow; such a bit is described as under-gauge. bit-sub n: a sub inserted between the drill collar and the bit. blank casing n: casing without perforations. blank flange n: a solid disk used to dead-end, or close off, a companion flange. blast hole drilling n: the drilling of holes into the earth for the purpose of placing a blasting charge (such as dynamite) in them. bleed v: to drain off liquid or gas, generally slowly, through a valve called a bleeder. To bleed down, or

blowout n: an uncontrolled flow of gas, oil, or other well fluids into the atmosphere. A blowout, or gusher, can occur when formation pressure exceeds the pressure applied to it by the amount of drilling fluid. A kick warns of an impending blowout. See formation pressure and kick. blowout preventer n: one of several valves installed at the wellhead to prevent the escape of pressure, either in the annular space between the casing and drill pipe or in open hole (i.e., hole with no drill pipe) during drilling completion operations. Blowout preventers on land rigs are located beneath the rig at the land's surface; and on floating offshore rigs, on the sea floor. See annular blowout preventer, inside blowout preventer, and ram blowout preventer. blowout preventer control panel n: a set of controls, usually located near the drillers position on the rig floor, that is manipulated to open and close the Blowout Preventers. blowout preventer control unit n: a service that stores hydraulic fluid under pressure in special containers and provides a method to open and close the Blowout Preventers quickly and reliably. Usually, compressed air and hydraulic pressure provide the opening and closing force in the unit. blowout preventer drill n: a training procedure to determine that rig crews are familiar with correct operating practices to be followed in the use of blowout prevention equipment. A "dry run" of blowout prevention action. (API Recommended Practice 53) BPLD abbr.: barrels of liquid per day, usually used in reference to total production of oil and water from a well.

blind drilling n: a drilling operation in which the drilling fluid is not returned to the surface. Sometimes blind-drilling techniques are resorted to when lost circulation occurs.

blowout preventer stack n pl: the assembly of well control equipment, including preventers, spools, valves and nipples connected to the top of the casing-head (API Recommended Practice 53)

blind ram n: an integral part of a Blowout Preventer that serves as the closing element on an open hole. Its ends do not fit around the drill pipe but seal against each other and shut off the space below completely. See ram.

blowout preventer test tool n: a tool to allow pressure testing of the Blowout Preventer stack and accessory equipment by sealing the well bore immediately below the stack. (API Recommended Practice 53)

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ã DTL 2001 – Rev 2

GLOSSARY

body n: any portion of API equipment between end connection, with or without internal parts, which contains well bore pressure. (API Specification 16A) boiling point n: the temperature at which the vapour pressure of a liquid becomes equal to the pressure exerted on the liquid by the surrounding atmosphere. The boiling point of water is 212(F or 100(C at atmospheric pressure (14.7 psig or 101.325 kPa). boil weevil n: (slang) an inexperienced rig or oil field worker; sometimes shortened to weevil. boil weevil corner n: (slang, obsolete) the work station of an inexperienced rotary helper, on the opposite side of the rotary from the pipe tracker. bolting n pl: threaded fasteners (studs, nuts, bolts and cap-screws) used to assemble pressure containing parts or join end or outlet connections. (API Specification 16A) BOP abbr.: see blowout preventer. BOP closing ratio (Ram BOP) n: a dimension-less factor equal to the well bore pressure divided by the operating pressure necessary to close a Ram BOP against well bore pressure. Usually calculated for maximum rated well bore pressure. (API Recommended Practice 16E)

bottom hole pressure bomb n: a bomb used to record the pressure in a well at a point opposite the producing formation. bottom hole temperature n: temperature measured in a well at a depth at the midpoint of the thickness of the producing zone. bottoms up n: a complete trip from the bottom of the well bore to the top. bottoms-up gas n: gas that has risen to the surface from previously drilled gas bearing formations. (API Recommended Practice 64). bottom-supported drilling vessels n pl: offshore drilling vessels which float to the desired drilling location and are either balasted or jacked up so that the vessel is supported by the ocean floor while in the drilling mode. Rigs of this type include platform, submersibles, swamp barges and jack-up drilling rigs. (API Recommended Practice 64) bourdon tube n: a flattened metal tube bent in a cure, which tends to straighten when pressure is applied internally. By the movements of an indicator over a circular scale, a Bourdon tube indicates the pressure applied. box n: the female section of a connection. See tool joint. box and pin n: See tool joint.

BOP stack maximum rated well bore pressure n: the pressure containment rating of the ram Blowout Preventer's in a stack. In the event that the rams are rated at different pressures, the Blowout Preventer Stack Maximum Rated Well bore Pressure is considered equal to the lowest rated ram Blowout Preventer pressure. In stacks which do not contain any ram Blowout Preventer, the Blowout Preventer stack maximum rated well bore pressure is considered equal to the lowest rated Blowout Preventer pressure. (API Recommended Practice 16E)

Boyle's law n: a gas law that concerns pressure. It states that for any ideal gas or mixture of ideal gases at any definite temperature, the product of the absolute pressure times the volume is a constant (PV = K) bpd or BPD abbr.: barrels per day BPH abbr.: barrels per hour; used in drilling reports.

BOPD abbr.: barrels of oil per day

Bradenhead n: (obsolete) casing head.

BOPE abbr.: an abbreviation for Blowout Preventer equipment.

Bradenhead flange n: a flanged connection at the top of the oil well casing.

bore n: 1. The inside diameter of a pipe or a drilled hole. 2. The diameter of the cylinder of an engine. borehole n: the well bore; the hole made by drilling or boring. See well bore. borehole pressure n: total pressure exerted in the well bore by a column of fluid and/or back pressure imposed at the surface. (API Recommended Practice 57). bottom hole n: the lowest or deepest part of a well. adj.: pertaining to the bottom of the well bore. bottom hole assembly n: the portion of the drilling assembly below the drill pipe. It can be very simple - composed of only the bit and drill collars - or it can be very complex and made up of several drilling tools. bottom hole pressure n: 1. the pressure at the bottom of a borehole. It is caused by the hydrostatic pressure of the drilling fluid in the hole and, sometimes, any back-pressure held at the surface, as when the well is shut in with a Blowout Preventer. When fluid is being circulated, bottom hole pressure is the hydrostatic pressure plus the remaining circulating pressure required to move the fluid up the annulus. 2. the pressure in a well at a point opposite the producing formation, as recorded by a bottom hole pressure bomb.

ã DTL 2001 – Rev 2

Bradenhead squeezing v: the process by which hydraulic pressure is applied to a well to force fluid or cement outside the well bore without the use of a packer. The Bradenhead, or casing head, is closed to shut off the annulus when making a Bradenhead squeeze. Although this term is still used, the term Bradenhead is obsolete. See annular space and casing head and squeeze. brake n: a device for arresting the motion of a mechanism, usually by means of friction, as in the draw-works brake. brake band n: a part of the brake mechanism, consisting of a flexible steel band line with asbestos or a similar material, that grips a drum when tightened. On a drilling rig, the brake band acts on the flanges of the draw-works drum to control the lowering of the travelling block and its load of drill pipe, casing, or tubing. brake block n: a section of the lining of a band brake; it is shaped to conform to the curvature of the band and is attached to it with countersunk screws. See brake band. break circulation v: to start the fluid pump for restoring circulation column. As the stagnant drilling fluid has thickened or gelled during the period of no circulation, a high pump pressure is usually required to break circulation.

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GLOSSARY

breaking strength n: the load under which a chain or rope breaks. break out v: 1. To unscrew one section of pipe from another section, especially drill pipe while it is being withdrawn from the well bore. During this operation, the tongs are used to start the unscrewing operation. 2. To separate, as gas from a liquid or water from an emulsion. breathe v: to move with a slight, regular rhythm. Breathing occurs in tanks of vessels when vapours are expelled and air is taken in. For example, a tank of crude oil expands because of the rise in temperature during the day and contracts as it cools at night, expelling vapours as it expands and taking in air as it contracts. Tubing breathes when it moves up and down in sequence with a sucker rod pump. breather n: a small vent in an otherwise airtight enclosure for maintaining equality of pressure within and without. bridge n: 1. An obstruction in the borehole, usually caused by the caving in of the wall of the borehole or by the intrusion of a larger boulder. 2. A tool placed in the hole to retain cement or other material that may later be removed, drilled out, or permanently. bridge plug n: a down hole tool, composed primarily of slips, a plug mandrel, and a rubber sealing element, that is run and set in casing to isolate a lower zone while an upper section is being tested or cemented. bridging material n: the fibrous, flaky or granular material added to cement slurry or drilling fluid to aid in sealing formations in which lost circulation has occurred. See lost circulation and lost circulation material. brine n: water that has a large quantity of salt, especially sodium chloride, dissolved in it; salt water. bring in a well v: to complete a well and put on producing status. broaching v: venting of fluids to the surface or to the seabed through channels external to the casing. (API Recommended Practice 57) Bscf/d abbr.: billion standard cubic feet per day. Btu abbr.: British thermal unit. bubble point n: 1. The temperature and pressure at which part of a liquid begins to convert to gas. For example, if a certain volume of liquid is held at constant pressure, but its temperature is increased, a point is reached when bubbles of gas begin to form in the liquid. That is the bubble point. 2. The temperature and pressure at which gas, held in solution in crude oil, breaks out of solution as free gas. buckling stress n: bending of the pipe which may occur due to deviation of the hole. The pipe may bend because of the angle of the hole or because of an abrupt deviation such as a dog leg. building test n: a test in which a well is shut in for a prescribed period of time and a bottom hole pressure bomb run in the well to record the pressure. From this data and from the knowledge of pressures in a nearby well, the effectiveness drainage radius or the presence of permeability barriers or other production deterrents surrounding the well bore can be estimated. bullet perforator n: a tubular device that, when lowered to a selected depth within a well, fire bullets through the casing to provide hole through which the formation fluids may enter the well bore.

14

bullhead squeezing v: the process by which hydraulic pressure is applied to a well to force fluid such as cement outside the well bore. Annular flow (returns) is prevented by a packer set in the casing above the perforations and/or in open hole. (API Recommended Practice 57) bull plug n: a threaded nipple with a rounded closed end, used to stop up a hole or close off the end of a line. bumpless transfer v: the transfer from main electrical supply to an alternate power supply without losing signal and/or memory circuit normally associated with poser interruption. (API Recommended Practice 16E) button-hole assembly n: that part of the drill string located directly above the drill bit. The components primarily include the drill collars and other speciality tools such as stabilisers, reamers, drilling jars, bumper subs, heavy weight drill pipe, etc. (API Recommended Practice 64) buoyancy n: the apparent loss of weight of an object immersed in a fluid. If the object is floating, the immersed portion displaces a volume of liquid the weight of which is equal to the weight of the object. bypass valve n: a valve that permits flow around a control valve, apiece of equipment, or a system. calibration n: comparison and adjustment to a standard of known accuracy. (API Specification 16A) cap a well v: to control a blowout by placing a very strong valve on the well head. See blowout. cap rock n: 1. Impermeable rock overlying an oil or gas reservoir. 2. The porous and permeable strata overlying salt domes that may serve as the reservoir rock. carbon dioxide n: a colourless, odourless gaseous compound of carbon and oxygen (CO2). A product of combustion and a filler for fire extinguishers, this heavier-than-air gas can collect in low-lying areas where it may displace oxygen and present the hazard of anoxia. carbon monoxide n: a colourless, odourless gaseous compound of carbon and oxygen (CO). A product of incomplete combustion, it is extremely poisonous to breathe. cascade system n: in respiratory systems, a series connection of air cylinders in which the output of air from one adds to that of the next. cased adj.: pertaining to a well bore in which casing has been run and cemented. cased hole n: a well bore in which casing has been run. case-hardened adj.: hardened (as for a ferrous alloy) so that the surface layer is harder than the interior. casing n: steel pipe placed in an oil or gas well as drilling progresses, to prevent the wall of the hole from caving in during drilling, to prevent seepage of fluids, and to provide a means of extracting petroleum if the well is productive. casing hanger n: a circular device with a frictional gripping arrangement, used to suspend casing in a well.

ã DTL 2001 – Rev 2

GLOSSARY

casing-head/spool n: a heavy, flanged steel fitting connected to the first string of casing. It provides a housing for slips and packing assemblies, allows suspension of intermediate and production strings of casing and supplies the means for the annulus to be sealed off. Also called a spool.

channelling n: the bypassing of oil in a water-drive field due to erratic or uncontrolled water encroachment. The natural tendency toward channelling is aggravated by excessive production rates, which encourage premature water encroachment.

casing pressure n: the pressure built up in a well between the casing and tubing or the casing and drill pipe.

Charle's law n: a gas law that states that at constant pressure the volume of a fixed mass or quantity of gas varies directly with the absolute temperature.

casing seat test n: a procedure whereby the formation immediately below the casing shoe is subjected to a pressure equal to the pressure expected to be exerted later by a higher drilling fluid density and back pressure created by a kick. (API Recommended Practice 59) casing shoe n: the rounded concrete bottom end of a string casing. (API Recommended Practice 64) casing string n: the entire length of all the joints of casing run in well. Casing is manufactured in lengths of about 30 feet (9 metres), each length or joint being joined to another as casing is run as well. casting n: 1. An object at or near finished shape obtained by solidification of a substance in a mould. v. 2. Pouring molten metal into a mould to produce an object of desired shape. (API Specification 16A) catalyst n: a substance that alters, accelerates, or instigates chemical reactions without itself being affected. cathode n: 1. One of two electrodes in an electrolytic cell, represented as the positive terminal of a cell. 2. In cathodic protection systems, the protected structure that is representative of the cathode and is protected by having a conventional current flow from an anode to the structure through the electrolyte. caustic soda n: sodium hydroxide, used to maintain an alkaline pH in drilling fluid and in petroleum fractions. Its formula is NaOH. caving n: collapsing of the walls of the well bore, also called sloughing. cavings n pl.: particles that fall off (are sloughed from) the wall of the well bore. Not the same as cuttings. cc abbr.: cubic centimetre. Celsius scale n: the metric scale of temperature measurement used universally by scientists. On this scale, 0 degrees represents the freezing point of water and 100 degrees its boiling point at a barometric pressure of 760 mm. Degrees Celsius are converted to degrees Fahrenheit by using the following equation: (F = 9/5 x (°C) + 32 The Celsius scale was formerly called the centigrade scale, now, however, the term Celsius is preferred in the International System of Units (SI).

check valve n: a valve that permits flow in one direction only. Commonly referred to as a one-way valve. If the gas or liquid starts to reverse, the valve automatically closes, preventing reverse movement. chemical analysis n: determination of the chemical composition of material. (API Specification 16A) chert n: a quartzitic rock with hardness equal to or harder than flint. choke n: a device with an orifice installed in a line to restrict the flow of fluids. Surface chokes are a part of the Christmas tree on a well and contain a choke nipple, or bean, with a small-diameter bore that serves to restrict the flow. Chokes are also used to control the rate of flow of the drilling fluid out of the hole when the well is closed in the Blowout Preventer and a kick is being circulated out of the hole. choke and kill valves n pl.: BOP stack mounted valves which are connected below the BOPs to allow access to the well bore to either choke or kill the well. (API Recommended Practice 16E) choke line n: a high pressure line connected below a BOP to direct well fluids from annulus to the choke manifold during well control operations. choke manifold n pl.: the arrangement of piping and special valves, called chokes, through which drilling fluid is circulated when the Blowout Preventers are closed and which is used to control the pressures encountered during a kick. See Blowout Preventer. Christmas tree n: the control valves, pressure gauges and chokes assembled at the top of a well to control the flow of oil and gas after the well has been drilled and completed. circulate v: to pass from one point throughout a system and back to the starting point. For example, drilling fluid is circulated out of the suction pit, down the drill pipe and drill collars, out the bit, up the annulus and back to the pits while drilling proceeds. circulate-and-weight method n: a method of killing well pressure in which circulation is commenced immediately and fluid weight is brought up gradually, according to a definite schedule. Also called concurrent method.

cement plug n: a portion of cement placed at some point in the well bore to seal it.

circulating device n: a flow control device such as a sliding sleever or side pocket mandrel, which is run on production/injection tubing for the purpose of establishing communications between tubing and the tubing annulus. (API Recommended Practice 57).

CFG abbr.: cubic feet of gas, used in drilling reports.

circulating fluid n: also called drilling fluid. See drilling fluid.

change rams v: to take rams out of a Blowout Preventer and replace them with rams of a different size or type. When the size of a drill pipe is changed, the size of the pipe rams must be changed to ensure that they seal around the pipe when closed.

Circulating head n: a device attached to the top drill pipe or tubing to allow pumping into the well without use of the kelly. (API Recommended Practice 59). Circulating pressure n: the pressure generated by the fluid pumps and exerted on the drill stem.

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GLOSSARY

Clamp connection n: a pressure sealing device used to join two items without using conventional bolted flange joints. The two items to be sealed are prepared with clamp hubs. These hubs are held together by a clamp containing two to four bolts. (API Recommended Practice 64)

conductor casing – onshore and bottom supported offshore installations n: a relatively short string of large diameter pipe which is set to keep the top of the hole and provide a means of returning the upflow drilling fluid from the well bore to the surface drilling fluid system onshore and bottom supported offshore installations. (API Recommended Practice 64)

closed-in pressure n: See formation pressure. close in v: 1. To temporarily shut in a well that is capable of producing oil or gas. 2. To close the Blowout Preventers on a well to control a kick. The Blowout Preventers close off the annulus so that pressure from below cannot flow to the surface. Closed loop circuit n: a hydraulic control circuit in which spent fluid is returned to the reservoir. (API Recommended Practice 16E) closing unit (closing system) n pl: the assembly of pumps, valves, line, accumulators, and other items necessary to open and close the Blowout Preventer equipment. (API Recommended Practice 59) closing ratio n: the ratio between the pressure in the hole and the operating-piston pressure needed to close the rams of a Blowout Preventer.

conductor casing – floating installations n: the first string of pipe installed below the structural casing on which the well head and Blowout Preventer equipment are installed. (API Recommended Practice 64) conductor pipe n: 1. A short string of large diameter casing used to keep the well bore open and to provide a means of conveying the upflowing drilling fluid from the well bore to the fluid pit. 2. A boot. conformance n: compliance with specified requirements. (API Specification 16A) constant choke-pressure method n: a method of killing a well that has kicked, in which the choke size is adjusted to maintain a constant casing pressure. This method does not work unless the kick is all or nearly all salt water, if the kick is gas , this method will not maintain a constant bottom hole pressure because gas expands as it rises in the annulus.

Closing-unit pump n: term for an electric or hydraulic pump on an accumulator, serving to pump hydraulic fluid under high pressure to the Blowout Preventers so that the preventers may be closed or opened.

constant pit-level method n: a method of killing a well in which the fluid level in the pit is held constant while the choke size is reduced and the pump speed increases to the point where the formation fractures or casing ruptures, and control of the well is lost.

Closure bolting n pl: fasteners used to assemble API Spec 16A equipment other than end and outlet connections. (API Specification 16A)

continental shelf n: a zone, adjacent to a continent, that extends from the low waterline to the point at which the sea floor slopes off steeply to 600 feet (183 m) deep or more.

cm sym: centimetre

continuous reeled tubing n pl: tubing stored on a reel that can be run in and out of a well without making a connection. (API Recommended Practice 57).

cm² sym: square centimetre cm³ sym: cubic centimetre collapse pressure n: the amount of force needed to crush the sides of pipe until it caves in on itself. Collapse occurs when the pressure outside the pipe is greater than the pressure inside the pipe. come out of the hole v: to pull the drill stem out of the well bore. This withdrawal is necessary to change the bit, change from a core barrel to the bit, run electric logs, prepare for a drill stem test, run casing, and so on. company man n: also called company representative. company representative n: an employee of an operating company whose job is to represent the company’s interests at the drilling location. compressibility factor n: a factor, usually expressed as Z, which gives the ratio of the actual volume of gas at a given temperature and pressure to the volume of gas when calculated by the ideal gas law without any consideration of the compressibility factor.

control fluid n: hydraulic oil or water-based fluid which, under pressure, pilots the operation of control valves or directly operates functions. (API Recommended Practice 16E) control hose bundle n pl: a group of pilot and signal hoses assembled into a bundle with an outer protective sheath. For subsea applications it may contain a hydraulic supply line. (API Recommended Practice 16E) control line n: a flexible hose or rigid line that transmits the hydraulic power fluid to a function. (API Recommended Practice 16E) control manifold n pl: the assemblage of valves, regulators, gauges and piping used to regulate pressures and control the flow of hydraulic power fluid to operate system functions. (API Recommended Practice 16E)

concentric operations n pl: well operations conducted using small diameter tubing inside conventional tubing or tubing-less completion’s, normally with the Christmas tree in place and using a small rig or hoisting unit. (API Recommended Practice 57).

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ã DTL 2001 – Rev 2

GLOSSARY

control panel n: an enclosure displaying an array of switches, push buttons, lights and/or valves and various pressure gauges or meters to control or monitor functions. Control panel types include: diverter panel, Driller’s panel, master panel and mini or auxiliary remote panel. All these panels are remote from the main hydraulic manifold and can be pneumatic, electric or hydraulic powered. (API Recommended Practice 16E) a)

diverter panel n: a panel that is dedicated to the diverter and flow line system functions. It is positioned for easy Driller’s access and visual observation of the activated functions.

b)

driller’s panel n: the BOP control panel mounted at the Drillers position on the rig floor.

c)

master panel (hydraulic or electric) n: the panel mounted in close proximity to the main accumulator unit. All control functions are operable from this panel, including all regulators and gauges.

d)

mini or auxiliary remote panel – a limited function panel mounted in a remote location for use as an emergency backup. On an offshore rig it is normally located in the Tool pusher’s office, and on a land rig, at least 100 feet from the prevailing wind.

control pod n pl: the assemblage of valves and pressure regulators which respond to control signals to direct hydraulic power fluid through assigned porting, to operate functions. (API Recommended Practice 16E). control valve (surface control system) n: a valve mounted on the hydraulic manifold which directs hydraulic power fluid to the selected function (such as annular BOP close) while simultaneously venting the opposite function (annular BOP open). (API Recommended Practice 16E). control valve (subsea control system) n: a pilot operated valve in the subsea control pod that directs power fluid pumps, rotary table and other equipment designed to perform well Workovers, re-Completions, and other work which requires removal of the Christmas tree and pulling or manipulation of the tubing. (API Recommended Practice 57) core n: a cylindrical sample taken form a formation for geological analysis. Usually a conventional core barrel is substituted for the bit and produces a sample as it penetrates the formation. v: to obtain a formation sample for analysis. core barrel n: a tubular device, usually form 10 to 60 feet long, run at the bottom of the drill pipe in place of a bit and used to cut a core sample. corrosion resistant ring grooves n pl: ring grooves lined with metal resistant to metal-loss corrosion. (API Specification 16A) cp. sym: centipoise. crew n: the workers on a drilling or workover rig, including the Driller, Derrickman, and rotary helpers. critical point n: 1. The point at which, in terms of temperature and pressure, a fluid cannot be distinguished as being either a gas or a liquid, the point at which the physical properties of a liquid and a gas are identical. 2. One of the places along the length of drilling line at which strain is exerted as pipe is run into or pulled out of the hole.

ã DTL 2001 – Rev 2

critical pressure n: the pressure needed to condense a vapour at its critical temperature. critical temperature n: the highest temperature at which a substance can be separated into two fluid phases – liquid and vapour. Above the critical temperature, a gas cannot be liquefied by pressure alone. crossover sub n: a sub used between two sizes or types of threads in the drill stem assembly. crude oil n: unrefined liquid petroleum. It ranges in gravity from 9( API to 55( API and in colour from yellow to black, and it may have a paraffin, asphalt, or mixed base. If a crude oil, or crude, contains a sizeable amount of sulphur or sulphur compounds, it is called a sour crude, if it has little or no sulphur, it is called a sweet crude. In addition, crude oils may be referred to as heavy or light according to API gravity, the lighter oils having the higher gravity’s. cubic centimetres n: a commonly used unit of volume measurement in the metric system equal to 10-6 cubic metre, or 1 millilitre. The symbol for cubic centimetre is cm³. cubic foot n: the volume of a cube, all edges of which measure 1 foot. Natural gas is usually measure in cubic feet, with most common standard cubic metre being measure at 60ºF and 14.65 psi. cubic metre n: a unit of volume measurement in the metric system, replacing the previous standard unit known as the barrel, which was equivalent to 35 imperial gallons or 42 United States gallons. The cubic foot metre equals approximately 6.2898 barrels. current method n: also called circulate-and weight method. circulate-and-weight method.

See

cut drilling fluid n: well control fluid which has been reduced in density or unit weight as a result of entrainment of less dense formation fluids or air. (API Recommended Practice 59). cuttings n pl: the fragments of rock dislodged by the bit and brought to the surface in the drilling fluid. They are not the same as cavings, which are particles that fall off the wall of the hole. Washed and dried samples of the cuttings are analysed by geologists to obtain information about the formations drilled. cylinder head n: the device used to seal the top of a cylinder. In modern drilling rig engines, it also houses the valves and has exhaust passages. In four-cycle operation, the cylinder head also has intake passages. cylinder liner n: a removable, replaceable sleeve that fits into a cylinder. When the sliding of the piston and rings wears out the liner, it can be replaced without the block having to be replaced. daily drilling report n: a record made each day of the operations on a working drilling rig. Darcy n: an unit of measure of permeability. a porous medium has a permeability of 1 darcy when a pressure of 1 atmosphere on a sample and 1 cm long an 1 cm² in cross section will force a liquid of 1-cp. viscosity through the sample at the rate of 1 cm³ per second. The permeability of reservoir rocks is usually so low that it is measured in millidarcy units. dart-type blowout preventer n: an inside preventer that is installed on top of the drill stem when the well is kicking though the drill stem. It is stabbed in the open position and then closed against the pressure. The valve that closes is dart shaped, therefore the name.

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GLOSSARY

date of manufacture n: the date of manufacturer’s final acceptance of finished equipment. (API Specification 16A) dead well n: 1. a well that has ceased to produce oil or gas, either temporarily or permanently. 2. a well that has kicked and has been killed. de-foamer n: any chemical that prevents or lessens frothing or foaming in another agent. degasser n: the device used to remove unwanted gas from a liquid, especially from drilling fluid. degree API n: a unit of measurement of the American Petroleum Institute that indicates the weight, or density, of oil. See API gravity. dehydrate v: to remove water from a substance. Dehydration of crude oil is normally accomplished by emulsion treating with emulsion breakers. The water vapour in natural gas must be removed to meet pipeline requirements, a typical maximum allowable water vapour content is 7 lb per MMcf. density n: the mass or weight of a substance per unit volume. For instance, the density of a drilling fluid may be 10 pounds per gallon (ppg), 74.8 pounds per cubic foot (lb/ft³). Specific gravity, relative density, and API gravity are other units of density. See API gravity, relative density, and specific gravity. depth n: 1. the distance to which the well is drilled, stipulated in a drilling contract as contract depth. Total depth is the depth after drilling is finished. 2. on offshore drilling rigs, the distance from the baseline of a rig or a ship to the uppermost continuous deck. 3. the maximum pressure that a diver attains during a dive, expressed in feet (metres) of sea water. de-sander n: a centrifugal device for removing sand from drilling fluid to prevent abrasion of the pumps. It may be operated mechanically or by a fast-moving stream of fluid inside a special cone shaped vessel, in which case it is sometimes called a hydro-cyclone. de-silter n: a centrifugal device for removing very fine particles, or silt, from drilling fluid to keep the amounts of solids in the fluid at the lowest possible point. Usually, the lower the solids content of fluid, the faster is the rate of penetration. The de-silter works on the same principle as a de-sander. deviation n: the inclination of the well bore from the vertical. The angle of deviation, angle of drift, or drift angle is the angle in degrees that shows the variation from the vertical as revealed by a deviation survey. diameter n: the distance across a circle, measured through its centre. In the measurement of pipe diameters, the inside diameter is that of the interior circle and the outside diameter that of the exterior circle. differential n: the difference in quantity or degree between two measurement of units. For example, the pressure differential across a choke is the variation between the pressure on one side to that on the other. differential pressure n: the difference between two fluid pressures, for example, the difference between the pressure in a reservoir and in a well bore drilled in the reservoir, or between atmospheric pressure at sea level and at 10.000 feet. also called pressure differential.

directional drilling n: intentional deviation of a well bore from the vertical. although well bores are normally drilled vertically, it is sometimes necessary or advantageous to drill at an angle from the vertical. controlled directional drilling makes it possible to reach subsurface areas laterally remote from the point where the bit enters the earth. It often involves the use of turbo-drills, Dyna-Drills whipstocks, or other deflecting tools. displacement n: the weight of a fluid (such as water) displaced by a freely floating or submerged body (such as an offshore drilling rig). If the body floats, the displacement equals the weight of the body. diverter n: a system used to control well blowouts encountered at relatively shallow depths and to protect floating rigs during blowouts encountered at relatively shallow depths and to protect floating rigs during blowouts by directing the flow away from the rig. Diverters differ from Blowout Preventers in that flow is not stopped, but rather the flow is redirected away from the rig. diverter control system n: the assemblage of pumps, accumulators, manifolds, control panels, valves, lines etc., used to operate the diverter system. (API Recommended Practice 64) diverter housing n: a permanent installation under the rotary table which houses the diverter unit. (API Recommended Practice 64). diverter packer n: refer to Annular Sealing Device diverter piping n: refer to Vent Line diverter unit n: the device that embodies the annular sealing device and its actuating means. (API Recommended Practice 64). doghouse n: 1. a small enclosure on the rig floor, used as office for the Driller or as a storehouse for small objects. 2. any small building used as an office, a change house, or a place for storage. dogleg n: 1. a short change of direction in the well bore, frequently resulting in the formation of a key seat. See key seat. 2. a sharp bend permanently put in an object such as a pipe. dome n: a geological structure resembling an inverted bowl, a short anticline that plunges on all sides. down-hole fluid motor n: also called a turbo-drill or Dyna–Drill. See turbo-drill and Dyna-Drill. downtime n: time during which rig operations are temporarily suspended because of repairs or maintenance. DP abbr.: drill pipe, used in drilling reports. Drake well n: the first US well drilled in search of oil. Some 69 feet deep, it was drilled near Titusville, PA., and completed in 1859. drill v: to bore a hole in the earth, usually to find and remove subsurface formation fluids such as oil and gas. drill ahead v: to continue drilling operations. drill bit n: the cutting or boring element used for drilling. See bit.

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ã DTL 2001 – Rev 2

GLOSSARY

drill collar n: a heavy, thick-walled tube, usually steel, used between the drill pipe and the bit in the drill stem to provide a pendulum effect to the drill stem and weight to the bit.

drilling break n: a sudden increase in the rate of penetration by the drill bit. It sometimes indicates that the bit has penetrated a high-pressure zone and thus warns of the possibility of a blowout.

drill collar sub n: a sub used between the drill string and the drill collars.

drilling contractor n: an individual or group of individuals that own a drilling rig and contract their services for drilling wells.

drill floor substructure n: the foundation structure on which the derrick, rotary table, draw-works and other drilling equipment are supported. (API Recommended Practice 64)

drilling crew n: a Driller, a Derrickman, and two or more helpers who operate a drilling or workover rig for one tour each day.

drill pipe n: heavy seamless tubing in the drill stem that allows fluid to be pumped down the drill stem but prevents flow back up the drill stem, a check valve.

drilling fluid n: circulating fluid, one function of which is to force cuttings out of the well bore and to the surface. Other functions are to cool the bit and to counteract down hole formation pressure. While a mixture of barite, clay, water and chemical additives is the most common drilling fluid, wells can also be drilled by using air, gas, water, or oilbased fluid as the drilling fluid.

drill pipe float n: a valve installed in the drill stem that allows fluid to be pumped down the drill stem but prevents flow back up the drill stem, a check valve.

drilling fluid additive n: any material added to drilling fluid to change some of its characteristics or properties.

drill pipe pressure n: the amount of pressure exerted inside the drill pipe as a result of circulating pressure, entry of formation pressure into the well, or both.

drilling fluid balance n: a beam balance consisting of a cup and a graduated arm carrying a sliding weight and resting on a fulcrum, used to determine the density or weight of drilling fluid.

drill pipe pressure gauge n: an indicator, mounted in the fluid circulating system, that measures and indicates the amount of pressure in the drill stem.

drilling fluid cake n: the sheath of fluid solids that forms on the wall of the hole when liquid from fluid filters into the formation; also called wall cake or filter cake.

drill pipe safety valve n: a special valve used to close off the drill pipe to prevent back-flow during a kick. It has threads to match the drill pipe in use.

drilling fluid circulation n: the process of pumping fluid downward to the bit and backup to the surface in a drilling or workover operation. See normal circulation and reverse circulation.

drill ship n: a self-propelled, ocean-going, floating, ship-shaped vessel, equipped with drilling equipment. (API Recommended Practice 64)

drilling fluid conditioning n: the treatment and control of drilling fluid to ensure that it has the correct properties. conditioning may include the use of additives, the removal of sand or other solids, the removal of gas, the addition of water, and other measures to prepare the fluid for conditions encountered in s specific well.

drill stem test (DST) n: the conventional method of formation testing. The basic drill stem test tool consists of a packer or packers, valves or ports that may be opened and closed from the surface, and two or more pressure-recording devices. The tool is lowered on the drill string to the zone to be tested. The packer or packers are set to isolate the zone from the drilling fluid column. The valves or ports are then opened, to allow for formation flow while the recorders chart flow pressures, and are then closed, to shut in the formation while the recorders chart static pressures. A sampling chamber traps clean formation fluids at the end of the test. Analysis of the pressure charts is an important part of formation testing. drill string float n: a check valve in the drill string that will allow fluid to be pumped into the well, but will prevent flow from the well through the drill pipe. (API Recommended Practice 53) drill under pressure v: to carry on drilling operations while maintaining a seal (usually with a rotating head) to prevent the well fluids from blowing out. Drilling under pressure is advantageous in that the rate of penetration is relatively fast, however, the technique requires extreme caution. driller n: the employee directly in charge of a drilling or workover rig and crew. His main duty is operation of the drilling and hoisting equipment, but he is also responsible for down-hole condition of the well operation of down-hole tools, and pipe measurements. driller’s BOP control panel n: also called driller’s console.

drilling fluid density n: a measure of the density of a drilling fluid expressed as pounds per gallon (ppg), pounds per cubic foot (lb/ft³), or kilograms per cubic metre (kg/m³). Fluid weight is directly related to the amount of pressure the column of drilling fluid exerts at the bottom of the hole. drilling fluid density recorder n: an instrument in the drilling fluid system which continuously measures drilling fluid density. (API Recommended Practice 53). drilling fluid engineer n: a person whose duty is to test and maintain the properties of the drilling fluid that are specified by the operator. drilling fluid flow indicator n: a device that continually measures and may record the flow rate of fluid returning from the annulus and flowing out of the fluid return line. If the fluid does not flow at a fairly constant rate, a kick or lost circulation may have occurred. drilling fluid flow sensor n: also called fluid-flow indicator. drilling fluid level recorder n: a device that measures and records the height (level) of the drilling fluid in the fluid pits. The level of the fluid in the pits should remain fairly constant during the drilling of a well. If the level rises, however, then the possibility of a kick or a blowout exists. Conversely, if the level falls, then loss of circulation may have occurred. See Pit Level Recorder.

driller’s method n: a well-killing method involving two complete and separate circulation’s, the first circulates the kick out of the well and the second circulates heavier fluid through the well bore.

ã DTL 2001 – Rev 2

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GLOSSARY

drilling fluid logging n: the recording of information derived from examination and analysis of formation cuttings made by the bit and of fluid circulated out of the hole. A portion of the fluid is diverted through a gas-detecting device. Cuttings brought up by the fluid are examined under ultraviolet light detect the presence of oil or gas. Fluid logging is often carried out in a portable laboratory set up at the well.

effective permeability n: a measure of the ability of a single fluid through a rock when the pore spaces of the rock are not completely filled or saturated with the fluid. effective porosity n: the percentage of the bulk volume of a rock ample that is composed of inter-connected pore spaces which allow the passage of fluid s through the sample. See porosity.

drilling fluid motor n: See Dyna-Drill and turbodrill. drilling fluid pit n: an open pit dug in the ground to hold drilling fluid or waste materials discarded after the treatment of drilling fluid. For some drilling operations, fluid pits are used for suction to the fluid pumps, settling of fluid sediments, and storage of reserve fluid. Steel tanks are much more commonly used for these purposes now, but they are still sometimes referred to as pits. drilling fluid pump n: a large, high-pressure reciprocating pump used to circulate the fluid on drilling rig. A typical fluid pump is a two cylinder, double-acting or three-cylinder, single-acting piston pump whose pistons travel in replaceable liners and are driven by a crankshaft actuated by an engine or motor. Also called a slush pump. drilling fluid return line n: refer to flow line. drilling fluid tank n: one of a series of open tanks, usually made of steel plate, through which the drilling fluid is cycled to allow sand and fine sediments to be removed. Additives are mixed with the fluid in the tanks, and the fluid is temporarily stored there before being pumped back into the well. Modern rotary drilling rigs are generally provided with three or more tanks, fitted with built-in piping, valves, and fluid agitators. Also called fluid pits. drilling spool n: a connection component with ends either flanged or hubbed. it must have an internal diameter at least equal to the bore of the Blowout Preventer and can have smaller side outlets for connecting auxiliary lines. (API Recommended Practice 53). drive pipe n: a relatively short string of large diameter pipe driven or forced into the ground to function as “conductor pipe”. (API Recommended Practice 53).

electric line n: single or multiple electrical conductor housed, within a braided wireline. (API Recommended Practice 57). electric pump n: an electrically driven hydraulic pump, usually a 3piston (triplex) pump. (API Recommended Practice 16E). electro-hydraulic (EH) system n: a control system that uses an electrical signal to actuate a solenoid operated hydraulic valve to hydraulically pilot a control valve to operate a function. (API Recommended Practice 16E). end and outlet connections n pl: integral flanges, studded or open faced, and hub connections used to join together equipment that contains or controls pressure. (API Specification 16A). equipment n: any single completed unit that can be used for its intended purpose without further processing or assembly. (API Specification 16A). equivalent circulating density (ECD) n: the sum of pressure exerted by hydrostatic head of fluid, drilled solids and friction pressure losses in the annulus, divided by the depth of interest and by 0.052, if ECD is to be expressed in pounds per gallon (lbs/gal). (API Recommended Practice 59). erosion n: the process by which material (such as rock or soil) is worn away or removed (as by wind or water). exploitation well n: a well drilled to permit more effective extraction of oil from a reservoir. sometimes called a development well.

dry hole n: any well that does not produce oil or gas in commercial quantities. A dry hole may flow water, gas or even oil, but not enough to justify production.

exploration well n: also called a wildcat.

duplex pump n: a reciprocating pump having two pistons or plungers, used extensively as a fluid pump on drilling rigs.

Fahrenheit scale n: a temperature scale devised by Gabriel Fahrenheit, in which 32 degrees represents the freezing point and 212 degrees the boiling point of water at standard sea-level pressure. Fahrenheit degrees may be converted to Celsius degrees by using the following formula: C = 5/9 x (F – 32)

Dyna-Drill n: a down hole motor driven by drilling fluid that imparts rotary motion to a drilling bit connected to the tool, thus eliminating the need to turn the entire drill stem to make hole. The Dyna-Drill, a trade name, is used in straight and directional drilling. dynamic well kill procedure n: a planned operation to control a flowing well by injecting fluid of a sufficient density and at a sufficient rate into the well bore to effect a kill without completely closing in the well with the surface containing equipment. (API Recommended Practice 64)

fault n: a break in subsurface strata. Often strata on one side of the fault line have been displaced (upward, downward, or laterally) relative to their original positions. fault n: a break in subsurface strata. Often strata on one side of the fault line have been displaced (upward, downward, or laterally) relative to their original positions. fault plane n: a surface along which faulting has occurred.

dynamically positioned drilling vessels n pl: drill-ships and semisubmersible drilling rigs equipped with computer controlled thrusters which enable them to maintain a constant position relative to the sea floor without the use of anchors and mooring lines while conducting floating drilling operations. (API Recommended Practice 64).

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fault trap n: a surface hydrocarbon trap created by faulting, which causes an impermeable rock layer to be moved opposite the reservoir bed. feed-in (influx, inflow) n: the flow of fluids from the formation into the well bore. (API Recommended Practice 59).

ã DTL 2001 – Rev 2

GLOSSARY

fill the hole v: to pump drilling fluid into the well bore while the pipe is being withdrawn, in order to ensure that the well bore remains full or fluid even though the pipe is withdrawn. Filling the hole lessens the danger of blowout or of caving of the wall of the well bore. fill-up (flood valve) n: a differentially set valve, installed on marine risers that automatically permits sea water to enter the riser to prevent collapse under hydrostatic pressure after evacuation caused by lost circulation or by gas circulated into the riser. (API Recommended Practice 53). filter cake n: 1. compacted solid or semisolid material remaining on a filter after pressure filtration of fluid with a standard filter press. Thickness of the cake is reported in thirty-seconds of an inch or in millimetres. 2. the layer of concentrated solids from the drilling fluid or cement slurry that forms on the walls of the borehole opposite permeable formations, also called wall cake or fluid cake.

float n: an element of a level-control assembly designed to operate while partially or completely submerged in a liquid, the level of which is controlled by the assembly. the buoyancy of the liquid activates the float and the control valve to which it is linked and modifies the rate of the inflow or the outflow of the vessel to maintain a pre-set level. Sometimes a drill pipe float is called simply a float. float valve n: a drill pipe float. flow coupling n: a heavy walled nipple or fitting designed to resist erosion that can result from turbulence created by a restriction in the flow string. (API Recommended Practice 57). flow line n: the piping which exits the bell nipple and conducts drilling fluid and cuttings to the shale shaker and drilling fluid pits. (API Recommended Practice 64).

filter loss n: the amount of fluid that can be delivered through a permeable filter medium after being subjected to a set differential pressure for a set length of time.

flow line sensor n: a device to monitor rate of fluid flow from the annulus. (API Recommended Practice 59).

final circulating pressure n: drill pressure required to circulate at the selected kill rate adjusted for increase in kill drilling fluid density over the original drilling fluid density. Used from the time kill drilling fluid reaches the bottom of the drill string until kill operations are completed, or a change in either kill drilling fluid density or kill rate is effected. (API Recommended Practice 59).

flow line valve n: a valve which controls the flow of drilling fluid through the flow line. (API Recommended Practice 64)

fish n: an object that is left in the well bore during drilling or workover operations and that must be recovered before work can proceed. It can be anything from a piece of scrap metal to a part of the drill stem. v: 1. to recover from a well any equipment left there during drilling operations, such as a lost bit or drill collar or part of the drill string. 2. to remove from an older well certain pieces of equipment (such as packers, liners, or screen pipe) to allow reconditioning of the well. fixed choke n: a choke, whose opening is one size only, its opening is not adjustable. flammable liquid n: any liquid having a flash point of 100(F (37.78(C) or less. these liquids are easily ignited. (API Recommended Practice 57) flange n: a projecting rim or edge (as on pipe fittings and openings in pumps and vessels) usually drilled with holes and having a sealing mechanism, used to join pressure containing equipment by bolting to other flanged fittings. (API Specification 16A). flange, blind n: a flange with no centre bore, used to close off completely a flanged end or outlet connection. (API Specification 16A). flare n pl: an arrangement of piping and burners used to dispose (by burning) of surplus combustible vapours, usually situated near a gasoline plant, refinery, or producing well. v: to dispose of surplus combustible vapours by igniting them in the atmosphere. Currently, flaring is rarely used because of the high value of gas as well as the stringent air pollution controls. flash point n: the minimum temperature at which a product momentarily ignites, but does not burn continuously. (API Recommended Practice 57). flex/ball joint n: a device installed directly above the subsea Blowout Preventer stack and at the top of the telescopic riser joint to permit relative angular movement of the riser to reduce stresses due to vessel motions and environmental forces.

ã DTL 2001 – Rev 2

fluid density n: the unit weight of fluid, e.g. pounds per gallon (lbs/gal). (API Recommended Practice 59). forging n: plastically deforming metal, usually hot, into desired shapes with compressive force, with open or closed dies. n: a shaped metal part formed by the forging method. (API Specification 16A) formation n: a bed or deposit composed throughout of substantially the same kind of rock, a lithologic unit. Each different formation is given a name, frequently as a result of the study of the formation outcrop at surface and sometimes based on fossils found in the formation. formation breakdown n: an event occurring when borehole pressure is a magnitude that the exposed formation accepts whole fluid from the borehole. (API Recommended Practice 59) formation competency test (formation integrity test) n: application of pressure by superimposing a surface pressure on a fluid column in order to determine ability of a subsurface zone to withstand a certain hydrostatic pressure. (API Recommended Practice 59) formation fluid n: fluid (such as gas, oil or water) that exists in a subsurface rock formation. formation fracture gradient n: the hydrostatic value expressed in psi./ft that is required to initiate a fracture in subsurface formation. (API Recommended Practice 64) formation pressure n: the force exerted by fluids in a formation, recorded in the hole at the level of the formation with the well shut in. Also called reservoir pressure or shut-in bottom-hole pressure. formation water n: the water originally in place in a formation. fracture gradient n: the pressure gradient (psi./ft) at which the formation accepts whole fluid from the well bore.

21

GLOSSARY

ft abbr.: foot ft² abbr.: square foot. ft³ abbr.: cubic foot. ft³/bbl abbr: cubic feet per barrel.

gauge pressure n: the amount of pressure exerted on the interior walls of a vessel by the fluid contained in it (as indicated by a pressure gauge), it is expressed in psig (pounds per square inch gauge) or in kilopascals. Gauge pressure plus atmospheric pressure equals absolute pressure. See absolute pressure. gel n: a semisolid. jelly like state assumed by some colloidal dispersions at rest. When agitated, the gel converts to a fluid state. Also a nickname for bentonite. v: to take the from of a gel, to set.

ft³/d abbr.: cubic feet per day. ft-lb abbr.: foot-pound. ft/min abbr.: feet per minute. ft³/min abbr.: cubic feet per minute

gel strength n: a measure of the ability of a colloidal dispersion to develop and retain a gel form, based on its resistance to shear. The gel strength, or shear strength of a drilling fluid determines its ability to hold solids in suspension. Sometimes bentonite and other colloidal clays are added to drilling fluid to increase its gel strength.

ft/s abbr.: feet per second.

glycol n: a group of compounds used to dehydrate gaseous or liquid hydrocarbons or to inhibit the formation of hydrates. Commonly used glycol’s are ethylene glycol, diethylene glycol, and triethylene glycol.

ft³/s abbr.: cubic feet per second.

go in the hole n: to lower the drill stem into the well bore.

function n: operation of a BOP, choke or kill valve or other component, in one direction (example, closing the blind rams is a function, opening the blind rams is a separate function). (API Recommended Practice 16E).

gpm abbr.: gallons per minute.

gal abbr.: gallon gallon n: a unit of measure of liquid capacity that equals 3.785 litres and has a volume of 231 in³. A gallon of water weighs 8.34 lb at 60ºF. T he imperial gallon, used in Great Britain, is equal to approximately 1.2 U.S. gallons. gas n: a compressible fluid that completely fills any container in which it is confined. Technically, a gas will not condense when it is compressed and cooled, because a gas can exist only above the critical temperature for its particular composition. Below the critical temperature, this form of matter is known as a vapour, because liquid can exist and condensation can occur. Sometimes the terms gas and vapour are used interchangeably. However, the term vapour should be only used for those streams in which condensation can occur and which originate from or are in equilibrium with, a liquid phase. gas buster n sl.: a slang term to denote a mud-gas separator. gas constant n: a constant number, mathematically the product of the total volume and the total pressure divided by the absolute temperature for 1 mole of any ideal gas or mixture of ideal gases at any temperature. gas-cut fluid n: a drilling fluid that has entrained formation gas giving the fluid a characteristically fluffy texture. When entrained gas is not released before the fluid returns to the well, the weight or density of the fluid column. Because a large amount of gas in fluid lowers its density, gas cut fluid must be treated to reduce the change of a blowout. gas drilling n: See air drilling.

graben n: a block of the earth’s crust that has slid downward between two faults, the opposite of a horst. gunk plug n: a volume of gunk slurry placed in the well bore. (API Recommended Practice 59) gunk-slurry n: a slang term to denote a mixture of diesel oil and bentonite. (API Recommended Practice 59) gunk squeeze n: procedure whereby a gunk slurry is pumped into a subsurface zone. (API Recommended Practice 59) hanger plug n: a device placed or hung in the casing below the Blowout Preventer stack to form a pressure-tight seal. Pressure is then applied to the Blowout Preventer stack in order to test it for leaks. hard shut-in v: to close in a well by closing a Blowout Preventer with the choke and/or choke line valve closed. (API Recommended Practice 59) hazardous substance n: a substance which by reason of being explosive, flammable, toxic, corrosive, oxidising, irritating or otherwise harmful, has the potential to cause injury, illness or death. (API Recommended Practice 57) head n: 1. the height of a column of liquid required to produce a specific pressure. See hydraulic head. 2. for centrifugal pumps, the velocity of flowing fluid converted into pressure expressed in feet or metres of flowing fluid. Also called velocity head. 3. That part of a machine (such as a pump or an engine) that is one the end of the cylinder opposite the crankshaft.

gas reservoir n: a geological formation containing a single gaseous phase. when produced, the surface equipment may or may not contain condensed liquid, depending on the temperature, pressure and composition of the single reservoir phase.

heat affected zone (HAZ) n: that portion of the base metal which has not been melted, but whose mechanical properties or microstructure has been altered by the heat of welding or cutting. (API Specification 16A)

gate valve n: a valve which employs a sliding gate to open or close the flow passage. The valve may or may not be full-opening. (API Recommended Practice 53).

heat (cast lot) n pl: material originating from a final melt. For remelted alloys, a heat shall be defined as the raw material originating from a single re-melted ingot. (API Specification 16A)

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ã DTL 2001 – Rev 2

GLOSSARY

heat treatment (heat treating) n: alternate steps of controlled heating and cooling of materials for the purpose of changing physical or mechanical properties. (API Specification 16A) heat treatment load n: that material placed on loading or carrying devices moved as a batch through one heat treatment cycles. (API Specification 16A). heave v: the vertical motion of a ship or a floating offshore drilling rig. heave compensator n: a device that moves with the heave of a floating offshore drilling rig to prevent the bit from being lifted off the bottom of the hole and then dropped back down (i.e., to maintain constant weight on the bit). It is used with devices such as bumper subs. See motion compensator. heavyweight drill pipe n: drill pipe having thicker walls and longer tool joints than usual and also an integral wear pad in the middle. Several joints of this pipe may be placed in the drill stem between drill collars and regular drill pipe to reduce the chances of drill pipe fatigue or failure. (Also known as heavy wall drill pipe.) heel n: the inclination of a ship or a floating offshore drilling rig to one side, caused by wind, waves, or shifting weights on board. high-pressure squeeze cementing n: the forcing of cement slurry into a well at the points to be sealed with a final pressure equal to or greater than the formation breakdown pressure. See squeeze cementing.

hp

abbr.: horsepower

hp-h

abbr.: horsepower-hour

HPNS

abbr.: high-pressure nervous syndrome.

H2S

form: hydrogen sulphide.

hull n: the framework of a vessel including all decks, plating, and columns, but excluding machinery. Hydrafrac n: the copyrighted name of a method of hydraulic fracturing for increasing productivity. hydrate n: a hydrocarbon and water compound that is formed under reduced temperature and pressure in gathering, compression, and transmission facilities for gas. Hydrates often accumulate in troublesome snow or ice. v: to enlarge by taking water on or in. hydration n: reaction of cement with water. The powdered cement gradually sets to a soldi as hydration continues. hydraulic connector n: a mechanical connector that is activated hydraulically and connects the BOP stack to the well-head or the LMRP to the BOP stack. See Lower marine Riser Package. (API Recommended Practice 16E).

hole n: 1. in drilling operations, the well bore or borehole. See well bore and borehole. 2. an opening that us made purposely or accidentally in any solid substance.

hydraulic control pod n: a device used on offshore drilling rigs to provide a way to actuate and control subsea Blowout Preventers from the rig. Hydraulic lines from the rig enter the pods, through which fluid is sent toward the preventer. Usually two pods, painted different colours, are used, each to safeguard and back up the other.

hole opener n: a device used to enlarge the size of an existing borehole, having teeth arranged on its outside circumference to cut the formation as it rotates.

hydraulic fluid n: a liquid of low viscosity (such as light oil) that is used in systems actuated by liquid (such as the brake system in a modern passenger car.)

hook n: a large, hook-shaped device from which the swivel is suspended. It is designed to carry maximum loads ranging from 100 to 650 tons (90 to 590 tonnes) and turns on bearings in its supporting housing. A strong spring within the assembly cushions the weight of a stand (90 feet or about 27 metres) of drill pipe, thus permitting the pipe to be made up and broken out with less damage to the tool joint threads. Smaller hooks without the spring are used for handling tubing and sucker rods.

hydraulic fracturing n: an operation in which a specially blended liquid is pumped down a well and into a formation under pressure high enough to cause the formation to crack open. The resulting cracks or fractures serve as passages through which oil can flow into the well bore.

hopper n: a large funnel or cone-shaped device into which dry components (such as powdered clay or cement) can be poured in order to uniformly mix the components with water or other liquids. the liquid is injected through a nozzle at the bottom of the hopper. The resulting mixture of dry material and liquid may be drilling fluid to be used as the circulating fluid in a rotary drilling operation, or it may be cement slurry to be used in bonding casing to the borehole. horsepower n: a unit of measure of work done by a machine. One horsepower equals 33.000 foot-pounds per minute. horst n: a block of the earth’s crust that has been raised up between two faults, the opposite of a graben. hose bundle n: see control hose bundle. hot working v: deforming metal plastically at such a temperature and rate that hardness and strength do not increase. (API Specification 16A)

ã DTL 2001 – Rev 2

hydraulic head n: the force exerted by a column of liquid expressed by the height of the liquid above the point at which the pressure is measured. Although head refers to distance or height, it is used to express pressure, since the force of the liquid column is directly proportional to its height. Also called head or hydrostatic head hydraulics n: the branch of science that deals with practical applications of water or other liquid in motion. Hydril n: the registered trademark of a prominent manufacturer of oil field equipment, especially the annular Blowout Preventer. hydrocarbons n pl: organic compounds of hydrogen and carbon, whose densities, boiling points, and freezing points increase as their molecular weights increase. Although composed of only two elements, hydrocarbons exist in a variety of compounds because of the strong affinity of the carbon atom for other atoms and for itself. The smallest molecules of hydrocarbons are gaseous, the largest are solids. Petroleum is a mixture of many different hydrocarbons. hydrochloric acid n: an acid compound commonly used to acidize carbonate rocks, prepared by mixing hydrogen chloride gas in water. Also known as muriatic acid. its chemical formula is HCl.

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GLOSSARY

hydroclone n: a cone-shaped separator for separating various sizes of particles and liquid by centrifugal force. See desander and desilter. hydrodynamic brake n: a device mounted on the end of the drawworks shaft of a drilling rig. The hydrodynamic brake serves as an auxiliary to the mechanical brake when pipe is lowered into the well. The braking effect of a hydrodynamic brake is achieved by means of an impeller turning in a housing filled with water. Sometimes called hydraulic brake or Hydromatic (a manufacturer’s term) brake. hydrogen sulphide (H2S) n: a flammable, colourless gaseous compound of hydrogen and sulphur (H2S) with the odour of rotten eggs. Commonly found in petroleum, it causes the foul smell of petroleum fractions. It is extremely corrosive and poisonous, causing damage to skin, eyes, breathing passages, and lungs and attacking and paralysing the nervous system, particularly that part controlling the lungs and heart. Also called hepatic gas or sulphured hydrogen. hydrogen sulphide service n: refers to equipment designed to resist corrosion and hydrogen embattlement caused by exposure to hydrogen sulphide. (API Recommended Practice 64). hydrophone n: an underwater listening device that converts acoustic energy to electrical signals. (API Recommended Practice 16E). hydrostatic head n: the true vertical length of fluid column, normally in feet. (API Recommended Practice 59). hydrostatic pressure n: the force exerted by a body of fluid at rest, it increases directly with the density and depth of the fluid and is expressed in psi or kPa. The hydrostatic pressure of fresh water is 0.433 psi per foot of depth (9.792 kPa/m). In drilling, the term refers to the pressure exerted by the drilling fluid in the well bore. In a water-drive field, the term refers to the pressure that may furnish the primary energy for production. IADC abbr.: International Association of Drilling Contractors, formerly the American Association of Oilwell Drilling Contractors (AAODC). idle v: to operate an engine without applying a load to it. igneous rock n: a rock mass formed by the solidification of material poured (when molten) into the earth’s crust or onto its surface. Granite is an igneous rock. impending blowout n: early manifestation or indication of a blowout. impermeable adj.: preventing the passage of fluid. a formation may be porous yet impermeable if there is an absence of connecting passages between the voids within it. See permeability. impression block n: a block with lead or another relatively soft material on its bottom. It is made up on drill pipe or tubing at the surface, fun into a well, and allowed to set on a tool or other object that has been lost in the well. When the block is retrieved the size, shape, and position of the fish are obtained from the examination of the impression left in the lead, and an appropriate fishing tool may be selected. in. abbr.: square inch.

inert gas n: the part of a breathing medium that serves as a transport for oxygen and is not used by the body as a life-support agent. Its purpose is to dilute the flow of oxygen to the lungs, thereby preventing oxygen toxicity. inflow n: see Feed-in influx n: see Feed-in inhibitor n: an additive used to retard undesirable chemical action in a product, added in small quantity to gasolines to prevent oxidation and gum formation, to lubricating oils to stop the colour change, and to corrosive environments to decrease corrosive action. initial circulating pressure n: drill pipe pressure required to circulate initially at the selected kill rate while holding casing pressure at the closed-in value, numerically equal to kill rate circulating pressure, plus closed-in drill pipe pressure. (API Recommended Practice 59). injection n: the process of forcing fluid into something. In a diesel engine, the introduction of high-pressure fuel oil into the cylinders. inland barge rig n: a drilling structure consisting of a barge upon which the drilling equipment is constructed. When moved from one location to another, the barge floats, but, when stationed on the drill site, the barge is submerged to rest on the bottom. Typically, inland barge rigs are used to drill wells in marshes, shallow inland bays, and areas where the water covering the drill site is not too deep. inner barrel n: the part of a telescopic slip joint on a marine riser which is attached to the flexible joint beneath the diverter. insert type packer n: a diverter element which uses inserts designed to close and seal on specific ranges of pipe diameter. (API Recommended Practice 64). inside blowout preventer n: a valve installed in the drill stem to prevent a blowout through the stem. Also called an internal Blowout Preventer. instrumentation n: a device or assembly of devices designed for one or more of the following functions: to measure operating variables (such as pressure, temperature, rate of flow, speed of rotation, etc) to indicate these phenomena with visible or audible signals, to record them, to control them within a predetermined range, and to stop operations if the control fails. Simple instrumentation might consist of an indicating pressure gauge only. In a completely automatic system, desired ranges of pressure, temperature, and so on are predetermined and preset. integral valve n: a valve embodied in the diverter unit which operates integrally with the annular sealing device. (API Recommended Practice 64) interlock n pl: an arrangement of control system functions designed to require the actuation of one function as a prerequisite to actuate another. (API Recommended Practice 64). intermediate casing string n: the string of casing set in a well after the surface casing is set to keep the hole from caving and to seal off troublesome formations. The string is sometimes called protection casing. internal blowout preventer n: also called inside Blowout Preventer. See inside blowout preventer.

indicated volume n: the change in meter reading that occurs during a receipt or delivery of a liquid product.

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GLOSSARY

internal upset n: an extra-thick wall on one end of tubing or drill pipe at the point where it is threaded to compensate for the metal removed in threading. Unlike conventional drill pipe, which has the extra thickness on the outside, drill pipe with internal upset has the extra thickness inside and a uniform, straight wall outside. internal-upset pipe n: tubular goods in which the pipe walls at the threaded end are thickened (upset) on the inside to provide extra strength in the tool joints. Thus the outer wall of the pipe is the same diameter throughout its length. Upset casing is normally run at the top of long strings in deep operations. international system of units n: a system of units measurement based on the metric system, adopted and described by the Eleventh General Conference of Weights and measures. It provides an international standard of measurement to be followed when certain customary units, both API (Field Units) and metric, are eventually phased out of international trade operations. The symbol SI (le Systeme International d’Unites) designates the system, which involves seven base units. 1. metre for length, 2. kilogram for mass, 3. second for time, 4. Kelvin for temperature, 5. ampere for electric current, 6. candela for luminous intensity, and 7. mole for amount of substance. From these units others are derived without introducing numerical factors. interval n: a designated portion of a zone. (API Recommended Practice 57). intrusive rock n: an igneous rock that, while molten, penetrated into or between other rocks and solidified. invaded zone n: an area within a permeable rock adjacent to a well bore into which a filtrate (usually water) from the drilling fluid has passed, with consequent partial or total displacement of the fluids originally present in the zone. iron roughneck n: manufacturer’s term for a floor-mounted combination of a spinning wrench and a torque wrench. The iron roughneck moves into a position hydraulically and eliminates the manual handling involved with suspended individual tools. iron sponge process n: a method of removing small concentrations of hydrogen sulphide from natural gas by passing the gas over a bed of wood shavings which have been impregnated with a form of iron oxide. The impregnated wood shavings are called iron sponge. The hydrogen sulphide reacts with the iron oxide, forming iron sulphide and water. isogonic chart n: a map that shows the isogonic lines joining point of magnetic declination, which is the variation between magnetic north and true north. For example, in Los Angeles, California, when the compass needle is pointing toward north, true north acutally lies 15° east of magnetic north. isogonic line n: an imaginary line on a map that joins places on the earth’s surface at which the variation of a magnetic compass needle from true north is the same. This variation, which may range from 0 to 30 or more degrees either east or west of true north, must be compensated for to obtain an accurate reading of direction. IWCF n: the International Well Control Forum, established on 1 January 1993, is an industry membership organisation whose function is to provide an international competency assessment standard for personnel involved in well operations. jacket n: tubular piece of steel in a tubing-liner type of sucker rod pump, inside of which is placed an accurately bored and honed liner. In this type of sucker rod pump, the pump plunger moves up and down within the liner, and liner is inside the jacket.

ã DTL 2001 – Rev 2

jack-up drilling rig n: an offshore structure with tubular or derrick legs that support the deck and hull. When positioned over the drilling site, the bottoms of the legs rest on the sea floor. A jack-up rig is towed or propelled to a location with its leg up. Once the legs are firmly positioned on the bottom, the deck and hull height are adjusted and levelled. jar n: a percussion tool operated mechanically or hydraulically to deliver a heavy hammer blow to objects in the borehole. Jars are used to free objects. jar accelerator n: a hydraulic tool used in conjunction with a jar and made up on the fishing string above the jar to increase the power of the hammer blow. jet n: 1. a hydraulic device operated by pump pressure to clean fluid pits and tanks in rotary drilling and to mix fluid components. 2. in a perforating gun using shaped charges, a highly penetrating, fast moving stream of exploded particles that cuts a hole in the casing, cement, and formation. jet bit n: a drilling bit having replaceable nozzles through which the drilling fluid is directed in a velocity stream to the bottom of the hole to improve the efficiency of the bit. See bit. joint n: a single length (30 feet or 9m) of drill pipe, drill collar, casing, or tubing that has threaded connections at both ends. Several joints screwed together constitute a stand of pipe. joule n: the unit used to measure heat, work and energy in the metric system. Its symbol is J. It is the amount of energy required to move an object of 1 kilogram mass to a height of 1 metre. Also called a newtonmetre. Joule-Thomson effect n: the change in gas temperature which occurs when the gas is expanded adiabatically from a higher pressure to a lower pressure. The effect for most gases, except hydrogen and helium, is a cooling of the gas. junction box (J-Box) (electrical) n: an enclosure used to house the termination points of electrical cable and components. May also contain electrical components required for system operation. (API Recommended Practice 16E). junction box (J-Box) (hydraulic of pneumatic) n: a bolt-on plate having multiple stab-type terminal fittings used for quick connection of the multi-hose bundle to a pod, hose reel or manifold. (API Recommended Practice 16E). junk n: metal debris lost in a hole. Junk may be a lost bit, pieces of a bit, milled pieces of pipe, wrenches , or any relatively small object that impedes drilling and must be fished out of the hole. v: to abandon (as a non-productive well). junk basket n: a device made up on the bottom of the drill stem to catch pieces of junk from the bottom of the hole. Fluid circulation forces the junk into a barrel in the tool, where it is held by metal projections, or catchers. When the basket is brought back to the surface, the junk is removed. Also called a junk sub. junk sub n: also called a junk basket. See junk basket. kelly n: the heavy steel member, three-, four-, six-, or eight-0sided, suspended from the swivel through the rotary table and connected to the topmost joint of drill pipe to turn the drill stem as the rotary table turns. It has a bored passageway that permits fluid to be circulated into the drill stem and up the annulus, or vice versa.

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GLOSSARY

kelly bushing n: a special device that, when fitted into the master bushing, transmits torque to the kelly and simultaneously permits vertical movement of the kelly to make hole. It may be shaped to fit the rotary opening or have pins for transmitting torque. Also called the drive bushing. kelly cock n: a valve installed at one or both ends of the kelly. When a high-pressure back-flow begins inside the drill stem, the valve is closed to keep pressure off the swivel and rotary hose. kelly hose n: also called the fluid hose or rotary hose. See rotary hose. kelly saver sub n: a sub that fits the drill stem between the kelly and the drill pipe. Threads on the drill pipe mate with those of the sub, minimising wear on the kelly. kelly spinner n: a pneumatically operated device mounted on top of the kelly that, when actuated, causes the kelly to turn or spin. it is useful when the kelly or a joint of pipe is attached to it must be spun, that is, rotated rapidly for being made up. kelly valve, lower n: an essentially full-opening valve installed immediately below the kelly, with outside diameter equal to the tool joint outside diameter. Valve can be stripped in the hole for snubbing operations. (API Recommended Practice 53). Kelvin temperature scale n: a temperature scale with the degree interval of the Celsius scale and the zero point at absolute zero. On the Kelvin scale, water freezes at 273 K and boils at 373 K. See absolute temperature scale. key n: 1. a hook-shaped wrench that fits the square shoulder of a sucker rod and is used when rods are pulled or run into a pumping oilwell. Usually used in pairs; one key backs up and other breaks out or makes up the rod. Also called a rod wrench. 2. A slender strip of metal that is used to fasten a wheel or a gear onto a shaft. The key fits into slots in the shaft and in the wheel of gear. key seat n: 1. a channel or groove cut in the side of the hole of a well and parallel to the axis of the hole. A key seat results from the dragging of pipe on a sharp bend in the hole. 2. a groove cut parallel to the axis in a shaft or a pulley bore. kg abbr.: kilogram.

kill rate circulating pressure n: pump pressure required to circulate kill rate volume under non-kick conditions. (API Recommended Practice 59). kill sheet n: a printed form that contains blank spaces for recording information about killing an impending blowout, provided to remind personnel of necessary steps to kill a well. kill weight fluid n: a fluid whose density creates a hydrostatic pressure equal to or greater than the pressure of the formations exposed to the well bore. (API Recommended Practice 57). kinematic viscosity n: the absolute viscosity of a fluid divided by the density of the fluid at the temperature of viscosity measurement. knife valve n: a valve using a portal plate or blade to facilitate open and close operation. (API Recommended Practice 64). knockout n: A knockout is a type or separator which falls into one of two categories: Free water and total liquid knockouts. (API Specification 12J). a)

The free water knockout is a vessel used to separate free water from a flow stream of gas, oil and water. The gas and oil usually leave the vessel through the same outlet to be processed by other equipment. The water is removed for disposal.

b)

The total liquid knockout is normally used to remove the combined liquids from a gas stream.

kPa sym: kiloPascal. laminar flow n: a smooth flow of liquid in which no cross flow of fluid particles occurs between adjacent stream lines. land rig n: any drilling rig that is located on dry land. landing nipple n: a receptacle in a production string with an internal profile to provide for latching and sealing of various types of plugs or valves. (API Recommended Practice 157).

kick n: an entry of water, gas, or other formation fluid into the well bore during drilling. It occurs because the pressure exerted by the column of drilling fluid is not great enough to overcome the pressure exerted by the fluids in the formation drilled. If prompt action is not taken to control the kick or kick the well, a blowout may occur.

latch on v: to attach elevators to section of pipe to pull it out of or run it into the hole.

kill v: 1. In drilling, to prevent a threatened blowout by taking suitable preventative measures (e.g., to shut in the well with the Blowout Preventer, circulate the kick out ,and increase the weight of the drilling fluid). 2. In production to stop a well from producing oil and gas so that reconditioning of the well can proceed. Production is stopped by circulating water and fluid into the hole.

lb abbr.: pound

kill drilling fluid density n: the unit weight, e.g., pounds per gallon (lbs/gal) selected for the fluid to be used to contain a kicking formation. (API Recommended Practice 59). kill line n: a high-pressure fluid, circulate rate, expressed in fluid volume per unit time, which is to be used to circulate under kick condition, kill rate is usually some selected fraction of the circulating rate used while drilling. (API Recommended Practice 59).

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lay down pipe v: to pull drill pipe or tubing from the hole and place it in a horizontal position on a pipe rack.

lb/ft³ abbr.: pounds per cubic foot. leak-off test n: a gradual pressurising of the casing after the Blowout Preventers have been installed to permit estimation of the formation fracture pressure at the casing seat. lens-type trap n: a hydrocarbon reservoir consisting of a porous, permeable, irregularly shaped sedimentary deposit surrounded by impervious rock.

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GLOSSARY

lifting nipple n: a short piece of pipe with a pronounced upset, or shoulder, on the upper end, screwed into drill pipe, drill collars, or casing to provide a positive grip for the elevators; also called a lifting sub or a hoisting plug.

log n: a systematic recording of data, such as a driller’s log, fluid log, electrical well log, or radioactivity log. Many different logs are run in the wells to obtain various characteristics of hole formations. v: to record data.

lifting sup n: also called hoisting plug or lifting nipple.

longitude n: the arc or portion of the earth’s equator intersected between the meridian of a given place and the prime meridian (at Greenwich, England) and expressed either in degrees or in time.

light crude oil n: a crude oil of relatively high API gravity (usually 40 degrees or higher).

loss of circulation n: See lost circulation lime n: a caustic solid that consists primarily of calcium oxide (CaO). many forms of CaO are called lime, including the various chemical and physical forms of quicklime, hydrated lime, and even calcium lime. lime fluid n: a drilling fluid that is treated with lime to provide a source of soluble calcium in the filtrate in order to obtain desirable fluid properties for drilling shale or clay formations.

lost circulation n: the quantities of whole fluid lost to a formation, usually in cavernous, fissured, or coarsely permeable beds, evidenced by the complete or partial failure of the fluid to return to the surface or partial failure of the fluid to return to the surface as it is being circulated in the hole. Lost circulation can lead to a blowout and, in general, reduce the efficiency of the drilling operation. Also called lost returns.

limestone n: a sedimentary rock rich in calcium carbonate that sometimes serves a s reservoir rock for petroleum.

lost circulation material n: a substance added to cement slurries or drilling fluid to prevent the loss of cement or fluid to the formation. See bridging material.

limit switch n: a hydraulic pneumatic or electrical switch that indicates the motion or position of a device. (API Recommended Practice 16E).

lost circulation plug n: cement set across a formation that is taking excessively large amounts of drilling fluid during drilling operations.

line hanger n: a slip device that attaches the liner to the casing. liquefied natural gas n: a liquid composed chiefly of natural gas (i.e., mostly methane). Natural gas is liquefied to make it easy to transport if a pipeline is not feasible (as across a body of water). Not as easily liquefied as LPG, LNG must be put under low temperature and high pressure or under extremely low (cryogenic) temperature and close to atmospheric pressure to become liquefied. liquefied petroleum gas n: a mixture of heavier, gaseous, paraffinic hydrocarbons, principally butane and propane. these gases, easily liquefied at moderate pressure, may be transported as liquids but converted to gases on release of the pressure. Thus, liquefied petroleum gas is a portable source of thermal energy that finds wide application in areas where it is impractical to distribute natural gas. It is also used as a fuel for internal-combustion engines and has many industrial and domestic uses. Principal sources are natural and refinery gas, from which the liquefied petroleum gases are separated by fractionation. liquid n: a state of matter in which the shape of the given mass depends on the containing vessel, but the volume of the mass is independent of the vessel; a liquid is fluid that is almost incompressible. liquid-level gauge n: any device connected to a vessel, coupled with either a float in the vessel or directly with the fluid therein, and calibrated to give a visual indication of the liquid level. lithology n: 1. the study of rocks, usually macroscopic. 2. the individual character of a rock in terms of mineral composition, structure and so forth. litre n: a unit of metric measure of capacity equal to the volume occupied by 1 kg of water at 4ºC and at the standard atmospheric pressure of 760 mm. location n: the place where a well is drilled; also called well site. locking mechanism n: a support or restraint device. (API Recommended Practice 64).

lost returns n: loss of drilling fluids into the formation, resulting in a decrease in pit volume. (API Recommended Practice 53). lower ball joint n: a device located above a subsea Blowout Preventer stack that permits relative angular movements of marine riser elements to reduce bending stresses caused by the vessel offset, vessel surge and sway, and environmental forces. (API Recommended Practice 64). lower kelly cock n: also called drill stem safety valve. lower marine riser package (LMRP) n: the upper section of a twosection subsea BOP stack, consisting of the hydraulic connector, annular BOP, ball/flex joint riser adapter, flexible choke and kill lines, and subsea pods. This interfaces with the lower subsea BOP stack. (API Recommended Practice 16E). lubrication v: alternately pumping a relatively small volume of liquid into a closed well bore system and waiting for the fluid to fall toward the bottom of the well; provides method for sealing off pressure and thus should be rated for highest anticipated pressure. m sym: metre. macaroni-rig n: a workover rig, usually lightweight, that is specially built to run a string of ¾-inch or 1-inch in diameter. magnetic brake n: also called an elector-dynamic brake. make a connection v: to attach a joint of drill pipe onto the drill stem suspended in the well bore to permit deepening the well bore by the length of the joint added (30 feet or 9 m). make a trip v: to hoist the drill stem out of the well bore to perform one of a number of operations such as changing bits, taking a core, and so forth, and then to return the drill stem to the well bore. make-and-break v: To connect and disconnect. (API Specification 16A). make hole v: to deepen the hole made by the bit; to drill ahead.

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GLOSSARY

manifold n: an assemblage of pipe, valves and fittings by which fluid from one or more sources is selectively directed to various systems or components. (API Recommended Practice 16E).

measuring tank n: a calibrated tank that, by means of weirs, float switches, pressure switches, or similar devices, automatically measures the volume of liquid run in and then released. Measuring tanks are used in LACT systems. Also called metering tanks or dump tanks.

manipulator valve n: a three-position directional control valve that has the pressure inlet port blocked and the operator ports vented in the centre position. (API Recommended Practice 16E)

meridian n: a north-south line from which longitudes and azimuths are reckoned.

manometer n: a U-shaped piece of glass tubing containing a liquid (usually water or mercury) that is used to measure the pressure of gases or liquids. When pressure is applied, the liquid level in one arm brated markings beside one of the arms permits a pressure reading to be taken, usually in inches or millimetres. marine riser connector n: a fitting on top of the subsea Blowout Preventers to which the riser pipe is connected. marine riser system n: the extension of the well bore from the subsea Blowout Preventer stack to the floating drilling vessel which provides for fluid returns to the drilling vessel, supports the choke, kill and control liens, guides tools into the well and serves as a running string for the Blowout Preventer stack. (API Recommended Practice 64). marl n: a semisolid or unconsolidated clay, silt, or sand. March funnel n: a calibrated funnel used in field tests to determine the viscosity of drilling fluid. mast n: a portable derrick that is capable of being erected as a unit, as distinguished from a standard derrick that cannot be raised to a working position as a unit. For transporting by land, the mast can be divided into two or more sections to avoid excessive length extending from truck beds on the highway. master bushing n: a device that fits into the rotary table. It accommodates the slips and drives the kelly bushing so that the rotary motion of the rotary table can be transmitted to the kelly. Also called rotary bushing. mater valve n: normally the lowermost valve(s) in the vertical run of the Christmas tree. (API Recommended Practice 57). material performance bases n pl: capabilities which must be demonstrated, as a minimum, for material to satisfy the criteria of this standard. (API Specification 16A) maximum allowable working pressure n: the maximum allowable working pressure (MAWP) is the maximum pressure, permissible by the ASME Code at the top of the separator in its normal operating position for a designated temperature. (API Specification 12J). maximum anticipated surface pressure n: the highest pressure predicted to be encountered at the surface of the well. (API Recommended Practice 57). Mcf abbr.: 1,000 cubic feet of gas, commonly used to express the volume of gas produced, transmitted, or consumed in a given period.

meta-centre n: a point located somewhere on a line drawn vertically through the centre of buoyancy of the hull of a floating vessel with the hull in one position (e.g. level) and then another (e.g. inclined). when the hull inclines slightly to a new position, the centre of buoyancy of the hull also moves to a new position. If a second line is drawn vertically through the new centre of buoyancy, it intersects the first line at a point called the meta-centre. Location of the meta-centre is important because it affects the stability of floating vessels (such as mobile offshore drilling rigs). metamorphic rock n: a rock derived from pre-existing rocks by mineralogical, chemical, and structural alterations caused by processes within the earth’s crust. Marble is a metamorphic rock. methane n: a light, gaseous, flammable paraffin hydrocarbon. Ch4,that has a boiling point of -258ºF and is the chief component of natural gas and an important basic hydrocarbon for petrochemical manufacture. metre n: the fundamental unit of length in the metric system. Its symbol is m. It is equal to about 3.28 feet, 39.37 inches, or 100 centimetres. metric ton n: a measurement equal to 1000kg or 2,204.6 lb avoirdupois. In many oil-producing countries, production is reported in metric tons. One metric ton is equivalent to about 7.4 barrels (42 US gal = 1 bbl) of crude oil with a specific gravity of 0.84, or 36º API. In the SI system, it is called a tonne. mica n: a silicate mineral characterised by sheet cleavage. Biotite is ferro-magnesian black mica, and muscovite is potassic white mica. Sometimes mica is used as lost circulation material in drilling. micron n: one-millionth of a metre; a metric unit of measure of length equal to 0.001 mm. migration n: the movement of oil from the area in which it was formed to a reservoir rock where it can accumulate. millidarcy n: one-thousandth of a darcy. Mine Safety and Health Administration n: a US government agency that evaluates research in the causes of occupational diseases and accidents. Head-quarters in Arlington, Virginia, MSHA is responsible for administration of the certification of respiratory safety equipment. minimum internal yield pressure n: the lowest pressure at which permanent deformation will occur. (API Recommended Practice 53). mixing system n: a system that mixes a measured amount of water soluble lubricant and optional glycol to feed water and delivers it to a storage tank or reservoir. (API Recommended Practice 16E). mixing tank n: any tank or vessel used to mix components of a substance (as in the mixing of additives with drilling fluid).

Mcf/d abbr.: 1,000 ft3 of gas per day. md sym: millidarcy.

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MMcf abbr.: million cubic feet; a common unit of measurement for large quantities of gas.

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GLOSSARY

MMscf abbr.: million standard cubic feet per day. mobile offshore drilling rig n: a drilling rig that is used exclusively to drill offshore wells and that floats upon the surface of the water when being moved from one location to another. It may or may not float once drilling begins. The drill ship, semi-submersible drilling rig, and jack-up drilling rig are all mobile rigs; a platform rig is not. mol sym: mole mole n: the fundamental unit of mass of a substance. Its symbol is mol. A mole of any substance is the number of grams or pounds indicated by its molecular weight. For example, H20 has a molecular weight of approximately 18. Therefore, a gram mole of water is 18 grams of water; a pound mole of water is 18 pounds of water. Monel steel n: a nickel-base alloy containing copper, iron, manganese, silicon, and carbon. Non-magnetic drill collars are often made of this material. monkey board n: the Derrickman’s working platform. As pipe or tubing is run into or out of the hole, the Derrickman must handle the top end of the pipe, which may be as high as 90 feet (27 m) in the derrick or mast. The monkey board provides a small platform to raise him to the proper height for handling the top of the pipe. montmorillonite n: a clay mineral often used as an additive to drilling fluid. It is a hydrous aluminium silicate capable of reacting with such substances as magnesium and calcium. See bentonite. moon pool n: a walled round hole or well in the hull of a drill ship (usually in the centre) through which the drilling assembly and other assemblies pass while a well is being drilled, completed, or abandoned from the drill ship. moored vessels n: offshore floating drilling vessels which rely on anchors, chains, and mooring lines extended to the ocean floor to keep the vessel at a constant location relative to the ocean floor. (API Recommended Practice 64).

multiplex n: a system that uses multiple electronic signals that are coded and transmitted through a conductor pair. This eliminates the requirement of a dedicated conductor pair for each required signal. (API Recommended Practice 16E). NACE abbr.: National Association of Corrosion Engineers. National Association of Corrosion Engineers n: organisation whose function is to establish standards and recommended practices for the field of corrosion control. It is based in Houston, Texas. natural gas n: a highly compressible, highly expandable mixture of hydrocarbons having a low specific gravity and occurring naturally in gaseous form Besides hydrocarbon gases, natural gas may contain appreciable quantities of nitrogen, helium, carbon dioxide, hydrogen sulphide, and water vapour. Although gaseous at normal temperatures and pressures, the gases comprising the mixture that is natural gas are variable in form and may be found either as gases or as liquids under suitable conditions of temperature and pressure. natural gas liquids n: those hydrocarbons liquefied at the surface in field facilities or in gas processing plants. Natural gas liquids include propane, butane, and natural gasoline. needle valve n: a form of globe valve that contains a sharp-pointed, needle-like plug that is driven into and out of a cone-shaped seat to accurately control a relatively small rate of flow of a fluid. In a fuel injector, the fuel pressure forces the needle valve off its seat to allow injection to take place. newton n: the unit of force in the metric system; its symbol is N. A Newton is the force required to accelerate an object of 1 kilogram mass to a velocity of 1 metre per second in 1 second. Newtonian fluid n: a fluid in which the viscosity remains constant for all rates of shear if constant conditions of temperature and pressure are maintained. Most drilling fluids behave as non-Newtonian fluids, as their viscosity is not constant but varies with the rate of shear. newton-metre n: also called a joule. See joule.

motion compensator n: any device (such as a bumper sub or heave compensator) that serves to maintain constant weight on the bit in spite of vertical motion of a floating offshore drilling rig.

nipple up v: in drilling, to assemble the Blowout Preventer stack on the well head at the surface.

motor-generator rig n: a drilling rig driven by electric motors with current supplied by engine-driven generators at the rig.

nominal size n: a designated size that may be different from the actual size.

mousehole n: an opening through the rig floor, usually lined with pipe, into which a length of drill pipe is placed temporarily for later connection to the drill string.

non-magnetic drill collar n: a drill collar made of an alloy that does not affect the readings of a magnetic compass placed within it to obtain subsurface indications of the direction of a deviated well bore. Used in directional drilling.

Mpa sym: megapascal non-porous adj.: containing no interstices; having no pores. Mscf/D abbr: thousand standard cubic feet per day. MSHA abbr: Milne Safety and Health Administration. mud n: See Drilling Fluids mud-gas separator n: a device that separates gas from the fluid coming out of a well when gas cutting has occurred or when a kick is being circulated out. mud hopper n: See hopper.

ã DTL 2001 – Rev 2

non-retrievable control pod n: a pod that is fixed in place on the LRMP and not retrievable. (API Recommended Practice 16E). normal circulation n: the smooth, uninterrupted circulation of drilling fluid down the drill stem, out the bit, up the annular space between the pipe and the hole, and back to the surface. normal formation pressure n: formation fluid pressure equivalent to 0.465 psi per foot of depth from the surface. If the formation pressure is 4,650 psi at 10,000 feet, it is considered normal.

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GLOSSARY

nozzle n: 1. a passageway through jet bits that allows the drilling fluid to reach the bottom of the hole and flush the cuttings through the annuls. Nozzles comes in different sizes that can be interchanged on the bit to allow more or less flow. 2. the part of the fuel system of an engine that has small holes in it to permit fuel to enter the cylinder. Properly known as a fuel-injection nozzle. Also called a spray valve. The needle valve is directly above the nozzle.

oil sand n: 1. a sandstone that yields oil. 2. (by extension) any reservoir that yields oil, whether or not it is sandstone. oil shale n: a formation containing hydrocarbons that cannot be recovered by an ordinary oilwell but cannot be recovered by an ordinary oilwell but can be mined. After processing, the hydrocarbons and treatment of oil shale has until recently been too great to compete with the cost of oilwell drilling.

O & G abbr.: oil and gas; used in drilling reports. offset-well data n: information obtained from wells that are drilled in an area close to where a well is being drilled or worked over. Such information can be very helpful in determining how a particular well will behave or react to certain treatments or techniques applied to it. offshore n: the geographic area which lies seaward of the coastline. In general, the term coastline means the line of ordinary low water along that portion of the coast that is in direct contact with the open sea or the line marking the seaward limit of inland waters. offshore drilling n: drilling for oil in an ocean, gulf, or sea, usually on the continental shelf. A drilling unit for offshore operations may be a mobile floating vessel with a ship or barge hull, a semi-submersible or submersible base, a self-propelled or towed structure with jacking legs (jack-up drilling rig), or a permanent structure used as a production platform when drilling from mobile floating vessels or form a jack-up vessel, while development wells are drilled from platforms. offshore platform n: permanently installed bottom supported or connected offshore structure, equipped with drilling and/or production equipment for drilling and/or development of offshore oil and gas reservoirs. (API Recommended Practice 64).

oil-water contact n: the point or plane at which the bottom of an oil sand contacts the top of a water sand in a reservoir; the oil-water interface. oilwell pump n: any pump, surface or subsurface, that is used to lift fluids from the reservoir to the surface. See sucker rod pumping and hydraulic pumping. on-suction adj.: of a tank, open to pump suction. open-circuit regulator n: also called demand regulator. open formation n: a petroleum-bearing rock with good porosity and permeability. open hole n: 1. any well bore in which casing has not been set. 2. open and cased hole in which no drill pipe or tubing is suspended. 3. the portion of the well bore that has no casing. opening ratio n: the ratio of the well pressure to the pressure required to open the Blowout Preventer. (API Recommended Practice 53). operating company n: See operator.

offshore rig n: any of various types of drilling structures designed for use in drilling wells in oceans, seas, bays, gulfs, and so forth. Offshore rigs include platforms, jack-up drilling rigs, semi-submersible drilling rigs, submersible drill rigs and drill ships. OH abbr.: open hole; used in drilling reports. oil and gas separator n: an item of production equipment used to separate liquid components of the well stream from the gaseous elements. Separators are either vertical or horizontal and either cylindrical or spherical in shape. separation is accomplished principally by gravity, the heavier liquids falling to the bottom and the gas rising to the top. a float valve or other liquid-level control regulates the level of oil in the bottom of the separator. oil drilling fluid n: a drilling fluid in which oil is the continuous phase. Oil-base fluid and invert-emulsion fluid are types of oil fluids. They are useful in drilling certain formations that may be difficult or costly to drill with water-base fluid. oil-base drilling fluid n: an oil that contains from less that 2 percent up to 5 percent water. The water is spread out, or dispersed, in the oil as small droplets. oil-emulsion drilling fluid n: a water-base fluid in which water is the continuous phase and oil is the dispersed phase. The oil is spread out, or dispersed, in the water in small droplets, which are tightly emulsified so that they do not settle out. Because of its lubricating abilities, an oilemulsion fluid increases the drilling rate and ensures better hole conditions than other fluids. oil field n: the surface area overlying an oil reservoir or reservoirs. Commonly, the term includes not only the surface area, but also the reservoir, the wells, and the production equipment.

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operating pressure n: the operating pressure is the pressure in the vessel during normal operation. The operating pressure shall not exceed the MAWP, and is usually kept at a suitable level below the setting of the pressure relieving devices to prevent their frequent opening. (API Specification 12J). operator n: the person or company, either proprietor or lessee, actually operating an oilwell or lease. Generally, the oil company by whim the drilling contractor is engaged. organic rock n: rock materials produced by a plant or animal life (coal, petroleum, limestone, etc). organic theory n: an explanation of the origin of petroleum, which holds that the hydrogen and the carbon that make up petroleum come from plants and animals of land and sea. Furthermore, the theory holds that more of this organic material comes from very tiny creatures of swamp and sea than comes from larger creatures of land. outer barrel n: the part of a telescopic slip joint on a marine riser which is attached to tension lines. Tension is transferred through the outer barrel into the riser. (API Recommended Practice 64). out-of-gauge hole n: a hole that is not gauge, that is, of a size smaller or larger than the diameter of the bit used to drill the hole. overbalance n: the amount by which pressure exerted by the hydrostatic head of fluid in the well bore exceeds formation pressure. (API Recommended Practice 59). overboard (diverter) line n: refer to vent line.

ã DTL 2001 – Rev 2

GLOSSARY

overburden n: the pressure on a formation due to the weight of the earth material above that formation. For practical purposes, this pressure can be estimated at 1 psi/ft of depth. (API Recommended Practice 53).

pendulum assemble n: a bottom hole assembly composed of a bit and several large-diameter drill collars; it may have one or more stabilisers installed in the drill collar string. The assembly works on the principle of the pendulum effect.

overburden pressure n: the pressure exerted by the overburden on the formation targeted for drilling.

pendulum effect n: the tendency of the drill stem - bit, drill collars, drill pipe, and Kelly - to hang in a vertical position due to the force of gravity.

over-gauge hole n: a hole whose diameter is larger than the diameter of the bit used to drill it. An over-gauge hole can occur when a bit is not properly stabilised or does not have enough weight put on it.

penetration rate n: See rate of penetration

overshot n: a fishing tool that is attached to tubing or drill pipe and lowered over the outside of the wall of pipe or sucker rods lost or stuck in the well bore. A friction device in the overshot, usually either a basket or a spiral grapple, firmly grips the pipe, allowing the lost fish to be pulled from the hole. packed-hole assembly n: a drill stem that consists of stabilisers and special drill collars and is used to maintain the proper angle and course of the hole. This assembly is often necessary in crooked hole country. packed pendulum assembly n: a bottom hole assembly in which pendulum-length collars are swung below a regular packed-hole assembly. The pendulum portion of the assembly is used to reduce hole angle; it is then removed, and the packed-hole assembly is run above the bit. Packer n: a piece of down hole equipment, consisting of a sealing device, and an inside passage for fluids, used to block the flow of fluids through the annular space between the tubing and the wall of the well bore by sealing off the space between them. It is usually made up in the tubing string some distance above the producing zone. A sealing element expands to prevent fluid flow except through the inside bore of the packer and into the tubing. Packers are classified according to configuration, use, and method of setting and whether or not they are retrievable (that is, whether they can be removed when necessary, or whether they must be milled or drilled out and thus destroyed): Packer test n: application of hydraulic pressure either through the tubing or annulus to assure that the packer is properly set and sealed. (API Recommended Practice 57) packing element n: the annular sealing device in an annular Blowout Preventer or diverter. (API Recommend Practice 64) packoff or stripper n: a devise with an elastomer packing element that depends on pressure below the packing to effect a seal in the annulus. Used primarily to run or pull pipe under low or moderate pressures. This device is not dependable for service under high differential pressures. (API Recommended Practice 53) part n: an individual piece used in the assembly of a single equipment unit. (API Specification 16A) partial pressure n: the pressure exerted by one specific component of a gaseous mixture. Pascal n: the accepted metric unit of measurement for pressure and stress and a component in the measurement of viscosity. A Pascal is equal to a force of 1 Newton acting on an area if 1 square metre. It is symbol Pa.

ã DTL 2001 – Rev 2

percussion drilling n: 1. Cable-tool-drilling. 2. Rotary drilling in which a special tool called a hammer drill is used in combination with a roller cone bit. perforate v: to pierce the casing wall and cement to provide holes through which formation fluids may enter or to provide holes in the casing so that materials may be introduced into the annulus between the casing and the wall of the borehole. Perforating is accomplished by lowering into the well a perforating gun, or perforator, that fires electricity detonated bullets or shaped charges from the surface. period of roll n: the time required for a floating offshore drilling rig to roll from one side to the other and back. permanent guide base n: a structure attached to and installed with the foundation pile when a well is drilled from an offshore drilling rig. It is seated in the temporary guide base and serves as a well head housing. Also, guidelines are attached to it so that equipment (such as the Blowout Preventer) may be guided into place on the well head. permeability n: 1. A measure of the ease in which fluids can flow through a porous rock. 2. The fluid conductivity of a porous medium. 3. The ability of a fluid to flow within the interconnected pore network of a porous medium. See absolute permeability, and effective permeability. petroleum geology n: the study of oil-and gas bearing rock formations. It deals with the origin, occurrence, movement, and accumulation of hydrocarbon fuels. pH value n: a unit of measure of the acid or alkaline condition of a substance. A neutral solution (such as pure water) has a pH of 7; acid solutions are less than 7. The pH scale is a logarithmic scale; a substance with a pH 9 is more than twice as alkaline as a substance with a pH of 8. piggyback v: (nautical) to install anchors behind each other in tandem on the same mooring line. pilot bit n: a bit placed on a special device called a hole opener that serves to guide the devise into an already existing hole that is to be opened (made larger in diameter). The pilot bit merely guides, or pilots, the cutters on the hole opener into the existing hole so that the holeopening cutters can enlarge the hole to the desired size. pilot fluid n: hydraulic control fluid that is dedicated to the pilot supply system. (API Recommended practice 16E) pilot line n: a hydraulic line that transmits pilot fluid to a control valve. Pilot lines are normally grouped in a common bundle or umbilical. pilot response time n: for subsea systems, the time it takes when the hydraulic function valve is activated on the surface for the signal to travel through the pilot line and activate a control panel in the pod. (API Recommended Practise 16E)

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GLOSSARY

pin-drive master bushing n: a master bushing that has four drive holes corresponding to the four pins on the bottom of the pin-drive kelly bushing. pinion n: 1. A gear with a small number of teeth designed to mesh with a larger wheel or rack. 2. The smaller of a pair or the smallest of a train of gear wheels. pipe n: a long hollow cylinder, usually steel, through which fluids are conducted. Oil field tubular goods are casing (including liners), drill pipe, tubing, or line pipe. Casing, tubing, and drill pipe are designated by external diameter. Because lengths of pipe are joined by externaldiameter couplings threaded by standard tools, an increase in the wall thickness can be obtained only by decreasing the internal diameter. Thus, the external diameter is the same for all weights of the same-size pipe. Weight is expressed in pounds per foot or kilograms per metre. Grading depends on the yield strength of the steel. pipe protector n: a protector that prevents drill pipe from rubbing against the hole or against the casing. pipe rack n: a horizontal support for tubular goods. pipe ram n: a sealing component for a Blowout Preventer or well head. Unless special rams accommodating various pipe sizes are used, separate rams are necessary for each size (outside diameter) pipe in use pipe ram BOP n: a hydraulically operated system typically having two opposed ram assemblies that move radically inward to close on pipe in the well bore and seal he annular space. (API Recommended Practice 16E) pipe ram preventer n: a Blowout Preventer that uses pipe rams as the closing elements. pipe upset n: that part of the pipe that has an abrupt increase of dimension. pipe wiper n: a flexible disk-shaped device, usually made of rubber, with a hole in the centre through which drill pipe or tubing passes, used to wipe of fluid, or other liquid from the pipe as the pipe is pulled from the hole. pit level n: height of drilling fluid in the fluid pits. pit-level indicator n: one of a series of devices that continuously monitor the level of the drilling fluid in the fluid tanks. The indicator usually consists of float devices in the fluid tanks that sense the fluid level and transmit data to a recording and alarm device (a pit-volume recorder) mounted near the Driller's position on the rig floor. If the fluid level drops too low or rises too high, the alarm sounds to warn the Driller that he may be either losing circulation or taking a kick. pit-level recorder n: the gauge at the Driller's position that records data from the pit-level, indicator. Pit Volume Totalizer n: trade name for a type of pit-level indicator that combines all of the individual pit volume indicators and registers the total drilling fluid volume in the various tanks. (API Recommended Practice 53). plastic viscosity n: an absolute flow property indicating the flow resistance of certain types of fluids. Plastic viscosity is a measure of shearing stress.

plug n: any object or device that blocks a hole or passageway (as a cement plug in a borehole). plug and abandon v: to place a cement plug into a dry hole and abandon it. plug valve n: a valve whose mechanism consists of a plug with a hole through it on the same axis as the direction of fluid flow. Turning the plug 90 degrees opens or closes the valve. The valve may or may not be full opening. (API Recommended Practice 53). pneumatic adj.: operated by air pressure. pneumatic control n: a control valve that is actuated by air. Several pneumatic controls are used on drilling rigs to actuate rig components (clutches, hoists, engines, pumps, etc.). pod n: see control pod. poise n: the viscosity of a liquid in which a force of 1 dyne (unit of measurement of small amounts of force) exerted tangentially on a surface of 1 cm² of either of two parallel planes 1 cm apart will move one plane at the rate of 1 cm per second in reference to the other plane, with the space between the two planes filled with the liquid. polymer n: a substance that consists of large molecules formed from smaller molecules in repeating structural units. In petroleum refining, heat and pressure are used to polymerise light hydrocarbons into larger molecules, such as those that make up high-octane gasoline. In oil field operations, various types of organic polymers are used to thicken drilling fluid, fracturing fluid, acid, and other liquids. In petrochemical production, polymer hydrocarbons are used as the basis for plastics. polymer units n: a drilling fluid which has been added a polymer, a chemical that consists of large molecules that were formed from small molecules in repeating structural units, to increase the viscosity of the fluid. poppet valve n: a device that controls the rate of flow of fluid in a line or opens or shuts off the flow of fluid completely . When open, the sealing surface of the valve is moved away from a seat; when closed, the sealing surface contacts the seat to shut off flow. Usually, the direction of movement of the valve is perpendicular to the seat. Poppet valves are used extensively as pneumatic (air) controls on drilling rigs and as intake and exhaust valves in most internal-combustion engines. pop valve n: a spring-loaded safety valve that opens automatically when pressure exceeds the limits for which the valve is set. It is used as a safety device on pressurised vessels and other equipment to prevent damage for excessive pressure. It is also called a relief valve or a safety valve. pore n: an opening or space within rock or mass of rocks, usually small and often filled with some fluid (water, oil, gas, or all three). pore pressure (formation pressure) n: pressure exerted by the fluids within the pore space of a formation. (API Recommended Practice 59). porosity n: the condition of something that contains pores (such as rock formation). Portland cement n: the cement most widely used in oil wells. It is made from raw materials such as limestone, clay or shale, and iron ore. positive-displacement motor n: usually called a Dyna-drill. See Dyna Drill.

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ã DTL 2001 – Rev 2

GLOSSARY

post weld heat treatment n: any heat treatment subsequent to welding, including stress relief. possum belly n: 1. receiving tank situated at the end of the fluid return line. The flow of fluid comes into the bottom of the device and travels over baffles to control fluid over the shale shaker. 2. a metal box under a truck bed that holds pipeline repair tools. potable water n. a water supply that is acceptably pure for human consumption. on an offshore rig, it is usually produced by water-makers and uses a supply water for mixing control fluid for a subsea control system. (API Recommended Practice 16E). pounds per square inch gauge n: the pressure in a vessel or container as registered on a gauge attached to the container. the pressure reading does not include the pressure of the atmosphere outside the container. power fluid n: pressurised hydraulic fluid dedicated to the direct operation of functions. (API Recommended Practice 16E). power tongs n: a wrench that is used to make up or break out drill pipe, tubing, or casing on which the torque is provided by air or fluid pressure. Conventional tongs are operated by mechanical pull provided by a jerk line connected to a cat-head. ppg abbr.: pounds per gallon. ppm abbr.: parts per million.

pressure gradient n: a scale of pressure differences in which there is a uniform variation of pressure from point to point. for example, the pressure gradient of a column of water is about 0.433 psi/ft of vertical elevation. The normal pressure gradient in a formation is equivalent to the pressure exerted at any given depth by a column of 10 percent salt water extending from that depth to the surface (0.465 psi/ft or 10.518 kPa/m). pressure loss n: 1. a reduction in the amount of force a fluid exerts against a surface, usually occurring because the fluid is moving against the surface. 2. the amount of pressure gauge when drilling fluid is being circulated by the fluid pump. Pressure losses occur as the fluid is circulated. pressure relief valve n: a valve that opens at a preset pressure to relieve excessive pressures within a vessel or line. Also called a relief line, safety valve, or pop valve. pressure retaining part(s) or member(s) n pl: those parts not exposed to well bore fluid s whose failure to function as intended would result in a release well bore fluid to the environment such as closure bolts, clamps. (API Specification 16A) pressure test, blowout preventer n: the process of pressure testing internally a Blowout Preventer or Blowout preventer assemble. (API Recommended Practise 57) pressure vessel quality n: metallic material whose integrity is such that it can be used to safety contain pressure without risk of leakage or rupture. (API Specification 16A)

pre-charge n: se accumulator pre-charge. pressure n: the force that fluid (liquid or gas) exerts uniformly in all directions within a vessel, pipe, hole in the ground, and so forth, such as that exerted against the liner wall of a tank or that exerted against the liner wall of a tank or that exerted on the bottom of the well bore by drilling fluid. Pressure is expressed in terms of force exerted per unit of area, as pounds per square inch (psi) or grams or kilograms per square centimetre. pressure containing part(s) or member(s) n pl: those parts exposed to well bore fluids whose failure to function as intended would result in a release of well bore fluid to the environment, such a bodies, bonnets and stems. (API Specification 16A). pressure controlling part(s) or member(s) n pl: those parts intended to control or regulate the movement of well bore fluids, e.g. packing elements, rams, replaceable seats within a pressure containing member or part(s). (API Specification 16A).

preventer n: shortened form of Blowout Preventer. See blowout peventer preventive maintenance n: a system conducting regular checks and testing of equipment to permit replacement or repair of weakened or faulty parts before failure of the equipment results. primary cementing n: the cementing operation that takes place immediately after the casing has been run into the hole; used to provide a protective sheath around the casing, to segregate the producing formation, and to prevent the undesirable migration of fluids. See secondary cementing and squeeze cementing. primary well control n: prevention of formation fluid flow by maintaining a hydrostatic pressure equal to or greater than formation pressure. (API Recommended Practice 59)

pressure differential n: See differential pressure.

primary mover n: an internal-combustion engine that is the source of power for a drilling rig and oilwell drilling.

pressure-differentially-set valve n: a valve that is operated when its actuator senses a change in pressure of a pre-set limit. (API Recommended Practice 64).

production packer n: a devise installed in wells to effect a seal between the tubing string(s) and casing. (API Recommended Practise 57)

pressure drop n: a loss of pressure, resulting from friction, sustained by a fluid passing through a line, valve, fitting, or other device.

producing zone n: the zone or formation from which oil and gas is produces.

pressure equalisation valve (dump valve) n: a device used to control bottom riser annulus pressure by establishing direct communication with the sea. (API Recommended Practice 64).

propping agent n: a granular substance (sand grains, aluminium pellets, or other material) that is carried in suspension by the fracturing fluid and that serves to keep the cracks open when fracturing fluid is withdrawn after fracture treatment.

pressure gauge n: an instrument that measures fluid pressure and usually registers the difference between atmospheric pressure and the pressure of the fluid by indicating the effect of such pressures on a measuring element ( a column of liquid, a Bourdon tube, a weighted piston, a diaphragm, ot other pressure-sensitive device).

ã DTL 2001 – Rev 2

psi abbr.: pounds per square inch. psia abbr.: pounds per square inch absolute. Psia is equal to the gauge pressure plus the pressure of the atmosphere at that point.

33

GLOSSARY

psi-ft. abbr.: pounds per square inch per foot. psig abbr.: pounds per square inch gauge. pto abbr.: power take off. pull it green v: to pull a bit from the hole for replacement before it is greatly worn. pull out v: See come out of the hole. pumping unit n: the machine that imparts reciprocating motion to a string of sucker rods extending to the positive-displacement pump at the bottom of a well; usually a beam arrangement driven by a crank attached to a speed reducer. pump liner n: a cylindrical, accurately machined, metallic section that forms the working barrel of some reciprocating pumps. Liners are an inexpensive means of replacing worn cylinder surfaces, and in some pumps they provide a method of conveniently changing the displacement and capacity of the pumps.

Rankine temperature scale n: a temperature scale with the degree interval of the Fahrenheit scale and the zero point at absolute zero. On the Rankine scale, water freezes at 491.60º and boils at 671.69º. See absolute temperature scale. rate of penetration n: a measure of the speed at which the bit drills into formations, usually expressed in feet (metres) per hour or minutes per foot (metre). rated working pressure n: the maximum internal pressure equipment is designed to contain and/or control. Rated working pressure is not to be confused with test pressure. (API Specification 16A). rat-hole n: 1. a hole in the rig floor, 30-35 feet (9-11 m) deep, which is lined with casing that projects above the floor and into which the kelly and swivel are placed when hoisting operations are in progress. 2. a hole of a diameter smaller than the main hole and drilled in the bottom of the main hole. v: to reduce the size of the well bore and drill ahead. rat-hole connection n: the addition of a length of drill pipe or tubing to the active string. The length to be added is placed in the rat-hole, made up to the kelly, pulled out of the rat-hole, and made up into the string.

pump pressure n: fluid pressure arising from the action of a pump. pump-through tubing plug n: a plug set inside the tubing string which will not permit back flow, but will permit pumping through from the top side. (API Recommended Practice 57). pup joint n: a length of drill pipe, tubing, or casing shorter than 30 feet. PVT abbr.: 1. Pit Volume Totalizer. 2. pressure, volume and temperature. qualified personnel n pl: individuals with characteristics or abilities gained through training, experience, or both, as measured against the manufacturers established requirements. (API Specification 16A). quartz n: hard mineral composed of silicon dioxide; a common component in igneous, metamorphic, and sedimentary rocks. R abbr.: Rankine. See Rankine temperature scale. rabbit n: 1. a small plug that is run through a flow line to clean the line or to test for obstructions. 2. any plug left unintentionally in a pipeline during construction (as, a rabbit that ran into the pipe). rack pipe v: 1. to place pipe withdrawn from the hole on a pipe rack. 2. to stand pipe on the derrick floor when coming out of the hole. ram n: the closing and sealing component on a Blowout Preventer. One of three types – blind, pipe, or shear – may be installed in several preventers mounted in a stack on top of the well bore. Blind rams, when closed, form a seal on a hole that has no drill pipe in ti; pipe rams, when closed, seal around the pipe; shear rams cut through drill pipe and then form a seal. ram blowout preventer n: a Blowut Preventer that uses rams to seal off pressure on a hole that is with our without pipe. also called a ram preventer. Ram preventer n: also called a ram Blowout Preventer.

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readback n: an indication of a remote condition. (API Recommended Practice 16E). ream v: to enlarge the well bore by drilling it again with a special bit. Often a rat-hole is reamed or opened to the same size as the main well bore. See rat-hole. records n pl: retrievable information. (API Specification 16A). reel (hose of cable) n: a reel, usually power driven, that stores, pays-out and takes-up umbilicals, either control hose bundles or armoured electrical cables. (API Recommended Practice 16E) reference point n: also called gauge point. regulator (pressure) n: a hydraulic device that reduces upstream supply pressure to a desired (regulated) pressure. It may be manual or remotely operated and, once set, will automatically maintain the regulated output pressure unless reset to a different pressure. (API Recommended Practice 16E) relative density n: the ration of the mass of a given volume of a substance to the mass of a like volume of a standard substance, such as water or air. In conventional measurement units, specific gravity is similar to relative density. relief valve n: a device that is built into a hydraulic or pneumatic system to relieve (dump) any excess pressure. relief well n: a well drilled near and deflected into a well that is out of control, making it possible to bring the wild well under control. See wild well. remote BOP control panel n: a device, placed on the rig floor, that can be operated by the Driller to direct air pressure to actuating cylinders that turn the control valves on the main BOP control unit, located at a safe distance from the rig. remote choke panel n: a set of controls, usually placed on the rig floor, that is manipulated to control the amount of drilling fluid being circulated out through the choke manifold. This procedure is necessary when a kick is being circulated out of a well. See choke manifold.

ã DTL 2001 – Rev 2

GLOSSARY

remote control valve n: a valve which is controlled from a remote location.

rig n: the derrick or mast, draw-works, and attendant surface equipment of a drilling or workover unit.

replacement n: the process whereby a volume of fluid equal to the volume of steel in tubulars and tools withdrawn from the well bore is returned to the well bore. (API Recommended Practice 59)

rig floor n: the area immediately around the rotary table and extending to each corner of the derrick or the mast; the area immediately above the substructure on which the draw-works, rotary table, and so forth rest. Also called derrick floor and drill floor.

reservoir n: a subsurface, porous, permeable rock body in which oil and/or gas is stored. Most reservoir rocks are limestone’s, dolomites, sandstone’s, or a combination of these. The three basic types of hydrocarbon reservoirs are oil, gas and condensate. An oil reservoir generally contains three fluids – gas, oil, and water – with oil the dominant product. In the typical oil reservoir, these fluids occur in different phases because of the variance in their gravity’s. Gas, the lightest, occupies the upper part of the reservoir rocks; water, the lower part; and oil, the intermediate section. In addition to its occurrence as a cap or in solution, gas may accumulate independently of the oil; if so, the reservoir is called a gas reservoir. Associated with the gas, in most instances, are salt water and some oil. In a condensate reservoir, the hydrocarbons may exist as a gas, but, when brought to the surface, some of he heavier ones condense to a liquid. reservoir drive mechanism n: the process in which reservoir fluids are caused to flow out of the reservoir rock and into a well bore by natural energy. Gas drives depend on the fact that, as the reservoir is produced, pressure is reduced, allowing the gas to expand and provide the driving energy. Water-drive reservoirs depend on water pressure to force the hydrocarbons out of the reservoirs and into the well bore. reservoir pressure n: the pressure in a reservoir. reservoir rock n: a permeable rock that contains oil or gas in appreciable quantity. response time n: the time elapsed between activation of a function at the control panel and complete operation of the function. (API Recommended Practice 16E) retarder n: a substance added to cement to prolong the setting time so that the cement can be pumped into place. Retarder's are used for cementing in high-temperature formations. retrievable control pod n: a subsea pod that is retrievable remotely on a wire line. (API Recommended Practice 16E). returns n pl.: the fluid, cuttings, and so forth that circulate up the hole to the surface. reverse circulation n: the course of drilling fluid downward through the annulus and upward through the drill stem, in contrast to normal circulation in which the course is downward through the drill stem and upward through the annulus. Seldom used in open hole, but frequently used in workover operations. Also referred to as “circulating the short way”, since returns from bottom can be obtained more quickly than in normal circulation. reverse-circulation junk basket n: a special device that is lowered into the hole during normal circulation to a position over the junk to be retrieved. A ball is then pumped down to cause the drilling fluid to exit through nozzles in the tool, producing reverse circulation and creating a vacuum inside the tool so that the junk is sucked into it. rheology n: the study of the flow of gases and liquids, of special importance to fluid engineers and reservoir engineers.

ã DTL 2001 – Rev 2

ring-joint flange n: a special type of flanged connection in which a metal ring (resting in a groove in the flange) serves as a pressure seal between the two flanges. riser n: a pipe through which liquid travels upward; a riser pipe. See riser pipe. riser angle indicator n: an acoustic or electronic device used to monitor the angle of the flex joint on a floating offshore drilling rig. Usually, a small angle should be maintained on the flex joint to minimise drill pipe fatigue and wear and damage to the Blowout Preventers and to maximise the ease with which tools may be run. Also called azimuth angle indicator. riser connector (LMRP connector) n: a hydraulically operated connector that joins the Lower Marine Riser Package to the top of the lower BOP stack. (API Recommended Practice 16E) riser pipe n: the pipe and special fittings used on floating offshore drilling rigs to establish a seal between the top of the well bore, which is on the ocean floor, and the drilling equipment, located above the surface of the water. A riser pipe serves as a guide for the drill stem from the drilling vessel to the well head and as a conductor of drilling fluid from the well to the vessel. The riser consists of several sections of pipe and includes special devices to compensate for any movement of the drilling rig caused by waves. It is also called a marine riser. riser spider n: equipment used to support the marine riser while it is being run or retrieved. (API Recommended Practice 64) riser tensioned line n: a cable that supports the marine riser while compensating for vessel movement. rock n: an aggregate of different minerals. Rocks are divided into three groups on the basis of their mode of origin: igneous, metamorphic, and sedimentary. rock bit n: also called roller cone bit. See roller cone bit. roller cone bit n: a drilling bit made of two, three, or four cones, or cutters, that are mounted on extremely rugged bearings. Also called rock bits. The surface of each cone is made up of rows of steel teeth or rows of tungsten carbide inserts. ROP abbr.: rate of penetration. rotary n: the machine used to impart rotational power to the drill stem permitting vertical movement of the pipe for rotary drilling. Modern rotary machines have a special component, the rotary bushing, to turn the kelly bushing, which permits vertical movement of the kelly while the stem is turning. rotary bushing n: also called master bushing. rotary drilling n: a drilling method in which a hole is drilled by a rotating bit to which a downward force is applied. The bit is fastened to and rotated by the drill stem, which also provides a passageway through which the drilling fluid is circulated. Additional joints of drill pipe are added as drilling progresses.

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GLOSSARY

rotary hose n: a reinforced flexible tube on a rotary drilling rig that conducts the drilling fluid from the fluid pump and standpipe to the swivel and kelly; also called the fluid hose or the kelly hose. rotary line n: also called drilling line.

salt dome n: as dome that is caused by an intrusion of rock salt into overlying sediments. A piercement salt dome is one that has been pushed up so that it penetrates the overlying sediments, leaving them truncated. The formations above the salt plug are usually arched so that they dip in all directions away from the centre of the dome, thus frequently forming traps for petroleum accumulations.

rotary pump n: a pump that moves fluid by positive displacement, using a system of rotating vanes, gears, or lobes. The vaned pump has vanes extending radially from element mounted in the casing. The geared rotary pump uses opposite rotating, meshing gears or lobes.

salt water flow n: an influx of formation salt water into the well bore. (API Recommended Practice 53).

rotary slips n pl.: also called slips. See slips.

sandstone n: a detrital sedimentary rock composed of individual grains of sand (commonly quartz) that are cemented together by silica, calcium carbonate, iron oxide, and so forth. Sandstone is a common rock in which petroleum and water accumulate.

rotary support beams n: the steel beams of a substructure which supports the rotary table. (API Recommended Practice 64). rotary table n: the principal component of a rotary, or rotary machine, used to turn the drill stem and support the drilling assembly. It has a bevelled gear arrangement to create the rotational movement and an opening into which bushings are fitted to drive and support the drilling assembly.

saturation n: a state of being filled or permeated to capacity. sometimes used to mean the degree or percentage of saturation (as, the saturation of the pore space in a formation or the saturation of gas in a liquid, both in reality meaning the extent of saturation). scf abbr.: standard cubic feet. scf/d abbr.: standard cubic feet per day.

rotating blowout preventer n: also called a rotating head. SCR abbr.: Slow Circulating Rate. rotating drilling head n: a sealing device used to close off the annular space around the kelly in drilling with pressure at the surface, usually installed above the main Blowout Preventers. A rotating head makes it possible to drill ahead even when there is pressure in the annulus that the weight of the drilling fluid is not overcoming; the head prevents the well from blowing out. It is used mainly in drilling of formations that have low permeability. the rate of penetration through such formations is usually rapid. rotating stripper head n: a sealing device installed above the Blowout Preventers and used to close the annular space about the drill pipe or kelly when pulling or running pipe under pressure. (API Recommended Practice 64). round trip n: the action of pulling out and subsequently running back into the hole a string of drill pipe or tubing. making a round trip is also called tripping. sack n: a container for cement, bentonite, illuminate, barite, caustic, and so forth. Sacks (bags) contain the following amounts: Cement 94 lb (1 cu ft) Bentonite 100 lb Ilmenite 100 lb Barite 100 lm safety clamp n: a device used to suspend a rod string after the pump has been spaced or when the weight of the rod string must be taken off the pumping equipment. safety joint n: an accessory to fishing tool, placed above it. If the tool cannot be disengaged from the fish, the safety point permits easy disengagement of the string of pipe above the safety joint. Thus, part of the safety joint, as well as the tool attached to the fish remains in the hole and becomes part of the fish. safety valve n: 1. an automatic valve that opens or closes when an abnormal condition occurs (e.g., a pressure relief valve on a separator that opens if the pressure exceeds the set point, or the shutdown valve at the well head that closes if the line pressure becomes too high or too low). 2. a valve installed at the top of the drill stem to prevent flow out of the drill pipe if a kick occurs during tripping operations.

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SCR abbr.: silicon controlled rectifier. scrubber n: a scrubber is a type of separator which has been designed to handle flow streams with unusually high gas-to-liquid ratio. These are commonly used in conjunction with dehydrators, extraction plants, instruments or compressors for protection from entrained. (API Specification 12J) sea floor n: the bottom of the ocean; the seabed. secondary cementing n: any cementing operation after the primary cementing operation. secondary cementing includes a plug-back job, in which a plug of cement is positioned at a specific point in the well and allowed to set. Wells ate plugged to shut off bottom water or to reduce the depth of the well for the other reasons. secondary control n: the proper use of blowout prevention equipment to control the well in the event primary control is lost. sediment n: 1. the matter that settles to the bottom of a liquid; also called tank bottoms, basic sediment, and so forth. 2. in geology, buried layers of sedimentary rocks. sedimentary rock n: a rock composed of materials that were transported to their present position by wind or water. Sandstone, shale, and limestone are sedimentary rocks. selector valve n: a three position directional control valve that has the pressure inlet port blocked and the operator ports blocked in the centre position. (API Recommended Practice 16E) self-elevating drilling unit n: an offshore drilling rig, usually with a large hull. It ahs a mat or legs that ate lowered to the sea floor and a main deck that is raised above the surface of the water to a distance where it will not be affected by the waves. Also called a jack-up drilling rig.

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GLOSSARY

semi-submersible drilling rig n; a floating offshore drilling structure that has hulls submerged in the water not resting on the sea floor. Living quarters, storage space, and so forth are assembled on the deck. Semisubmersible rigs are either self-propelled or towed to a drilling site and either anchored or dynamically positioned over the site or both. They are more stable than drill ships and are used extensively to drill wells in deep and rough waters. separator n: a separator is a cylindrical or spherical vessel used in the field to remove well-stream liquid(s) from gas components. The separators remove may be either may be either two-phase or three-phase. Two-phase separators also remove the total liquid form the gas, while three-phase separators also remove free water from the hydrocarbon liquid. Corrosion consideration for separators shall be for the pressure containing parts of the vessel only, and as can be identified as falling within the requirements of the applicable sections of the ASME Code. Corrosion considerations for vessel internals (non-pressure parts) is the mutual agreement between the purchaser and the manufacturer. Material selection for corrosive fluids should be selected based on a review of related API or NACE publications for materials that conform to ASME Code. Consideration should be given to material selection as it relates to weight loss, sulphide stress cracking, chloride stress cracking, or other forms of corrosion. It is the responsibility of the user to determine what consideration for corrosion should be made to the vessel during its intended life (Reference ASME Code as applicable to corrosion). (API Specification 12J) serialisation n: assignment of a unique code to individual parts and/or pieces of equipment to maintain records. (API Specification 16A) shale n: a fine-grained sedimentary rock composed of consolidated silt and clay or fluid. Shale is the most frequently occurring sedimentary rock. shale shaker n: a vibrating screen used to remove cuttings from the circulating fluid in rotary drilling operations. The size of the openings in the screen should be carefully selected to be the smallest size possible that will allow 100 per cent flow of the fluid. Also called a shaker. shear ram n: the components in a Blowout Preventer that cut, or shear, through drill pipe and form a seal against well pressure. Shear rams are used in mobile offshore drilling operations to provide a quick method of moving the rig away from the hole when there is no time to trip the drill stem out of the hole. shear ram (BOP) (blind/shear rams) n: rams have cutting blades that will shear tubulars that may be in the well bore, while the rams close and seal against the pressure below. (API Recommended Practice 16E)

shut-in adj.: shut off to prevent flow. Said of a well, plant, pump, and so forth, when valves are closed at both inlet and outlet. shut-in bottom-hole pressure n: the pressure at the bottom of a well when the surface valves on the well are completely closed. The pressure is caused by fluids that exist in the formation at the bottom of the well. shut-in casing pressure n: pressure of the annular fluid on the casing when a well is shut in. shut-in drill pipe pressure n: pressure of the drilling fluid on the inside of the drill stem; used to measure the difference between hydrostatic pressure and formation pressure when a well is shut in after a kick and the fluid pump is off. shut-in pressure n: the pressure when the well is completely shut in, as noted on a gauge installed on the surface control valves. When drilling is in progress, shut-in pressure should be zero, because the pressure exerted by the drilling fluid should be equal to or greater than the pressure exerted by the formation through which the well bore passes. on a flowing, producing well, however, shut-in pressure should be above zero. shutoff valve n: a valve that closes a hydraulic or pneumatic supply line. (API Recommended Practice 16E) shuttle valve n: a valve with two or more supply pressure ports and only one outlet port. When fluid is flowing through one of the supply ports the internal shuttle seals off the other inlet port and allows flow to the outlet port only. (API Recommended Practice 16E) SIBHP abbr.: shut-in bottom-hole pressure; used in drilling reports. SICP abbr.: shut-in casing pressure. side-track v: to drill around drill pipe or casing that has become lodged permanently in the hole, using whipstock, turbo-drill, or other fluid motor. SIDPP abbr.: shut-in drill pipe pressure; used in drilling reports. silicon controlled rectifier n: a device that changes alternating current to direct by means of a silicon control gate. Commonly called SCR or Thyristor. single n: joint of drill pipe. single-shot survey n: a directional survey that provides a single record of the drift direction and off-vertical orientation of the hole. SIP abbr.: shut-in pressure, used in drilling reports.

sheave n: a wheel or rollers with a cross-section designed to allow a specific size of rope, cable, wireline or hose bundle to be routed around it at a fixed bend radius. Normally used to change the direction of, and support, the line. (API Recommended Practice 16E) shooting nipple assembly n: a fabricated length of pipe equipped with a wireline Blowout Preventer and pack-off installed above the Blowout Preventer stack to accommodate removal of logging or perforating tools and for protection against unexpected pressure while performing through-casing wireline operations. (API Recommended Practice 57) shut in v: 1. to close the valves on a well so that it stops producing. 2. to close in a well in which a kick has occurred. See Hard Shut In, Soft Shut In.

ã DTL 2001 – Rev 2

skid the rig v: to move a rig with a standard derrick from the location of a lost or completed hole preparatory to starting a new hole. Skidding the rig allows the move to be accomplished with little or no dismantling of equipment. slick line n: a smooth, single-strand, high-strength, steel wire used in wireline operations. (API Recommended Practice 57) slim-hole drilling n: drilling in which the size of the hole is smaller than the conventional hole diameter for a given depth. This decrease in hole size enables the operator to run smaller casing, thereby lessening the cost of completion.

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GLOSSARY

slip ram preventer n: a ram Blowout Preventer with pipe slips which, when engaged, prevents movement of the pipe but does not control flow. (API Recommended Practice 57)

space-our joint n: the joint of drill pipe which is used in hang off operations so that no tool joint is opposite a set of preventer rams. (API Recommended Practice 59)

slips n pl.: wedge-shaped pieces of metal with teeth or other gripping elements that are used to prevent pipe from slipping down into the hole or to hold pipe in place. Rotary slips fit around the drill pipe and wedge against the master bushing to support the pipe. Power slips are pneumatically or hydraulically actuated devices that allow the crew to dispense with the manual handling of slips when making a connection. Packers and other downhole equipment are secured in position by slips that engage the pipe by action directed at the surface.

SPE abbr.: Society of Petroleum Engineers. specific gravity n: the ratio of the weight of a given volume of a substance at a given temperature to the weight of an equal volume of a standard substance at the same temperature. For example, if 1 cubic inch of water at 39ºF weighs 1 unit and 1 cubic inch of another solid or liquid at 39º weights 0.95 unit, then the specific gravity of the substance is 0.95. In determining the specific gravity of gases, the comparison is made with the standard of air or hydrogen.

sloughing n: (pronounced “sloughing”). Also called caving. See caving. Slow Circulating Rate (SCR) n: a predetermined pump rate which can be used to kill a well which has experienced a kick. slug the pipe v: to pump a quantity of heavy fluid into the drill pipe. Before hoisting drill pipe, it is desirable (if possible) to pump into its top section a quantity of heavy fluid, or a slug, that causes the level of the fluid to remain below the rig floor so that the crew members and the rig floor are not contaminated with the fluid when stands are broken out. slurry n: a plastic mixture of cement and water that is pumped into a well to harden, where it supports the casing into a well to harden, where it supports the casing and provides a seal in the well bore to prevent migration of underground fluids. snubbing v: pulling or running tubulars under pressure through a resilient element where special equipment is used to apply external force to push the pipe into the well or to control pipe movement out of the well. (API Recommended Practice 57) SO2 form: sulphur dioxide. soft shut in v: to close in a well by closing a Blowout Preventer with the choke and choke lien valve open, then closing the choke while monitoring the casing pressure gauge for maximum allowable casing pressure. (API Recommended Practice 59) solenoid valve n: an electrically operated valve that controls a hydraulic or pneumatic pilot signal or function. (API Recommended Practice 16E) Solution n: a single, homogeneous liquid, solid or gas phase that is a mixture in which the components (liquid, gas, solid, or combinations thereof) are uniformly distributed throughout the mixture. In a solution, the dissolved substance is called the solute, the substance in which the solute is dissolved is called the solvent. stored hydraulic fluid volume n: the fluid volume recoverable from the accumulator system between the maximum designed accumulator operating pressure and the precharge pressure. (API Recommended Practice 16E) sour adj. Containing or caused by hydrogen sulphide or another acid gas (e.g., sour crude, sour gas, sour corrosion). sour crude oil n: oil containing hydrogen sulphide or another acid gas. sour gas n: natural gas containing hydrogen sulphide. space out v: procedure conducted to position a predetermined length pipe above the rotary table so that a tool joint is located above the subsea preventer rams on which drill pipe is to be suspended (hung-off) and so that no tool joint is opposite a set of preventer rams after drill pipe is hung-off. (API Recommended Practice 59)

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spent fluid n: hydraulic fluid that is vented from a function control port when the opposite function is operated. splash zone n: the area on an offshore structure that is regularly wetted by seawater but is not continuously submerged. Metal in the splash zone must be well protected from the corrosive action of seawater and air. spool n: a pressure containing piece of equipment having API end connections, used below or betweeen equipment functioning to space apart, adapt or provide outlets in an equipment assembly. When outlet connections are provided, they shall be API connections. (API Specification 16A) spud v: to move the drill stem up and down in the hole over a short distance without rotation. Careless execution of this operation creates pressure surges that can cause a formation to break down and results in lost circulation. See spud in. spud in v: to begin drilling, to start the hole. square drill collar n: a special drill collar, square but with rounded edges, used to control the straightness or direction of the hole, often part of a packed-hole assembly. square-drive master bushing n: a master bushing that has a square opening or recess to accept and drive the square that is on the bottom of the square-drive kelly bushing. squeeze n: 1. a cementing operation in which cement is pumped behind the casing under high pressure to re-cement channelled areas or to block off an uncemented zone. 2. the increasing of external pressure upon a diver’s body by improper diving technique. squeeze cementing n: the forcing of cement slurry by pressure to specified points in a well to cause seals at the points of squeeze. It is a secondary cementing method that is used to isolate a producing formation, seal off water, repair casing leaks, and so forth. squench joint n: a special thread-less tool joint for large-diameter pipe, especially conductor pipe, sometimes used on offshore drilling rigs. When the box is brought down over the pin and weight is applied, a locking device is required to make up these joints, their use can save time when the conductor pipe is being run. stab v: to guide the end pipe into coupling or tool joint when making up a connection. stabbing board n: a temporary platform erected in the derrick or mast, some 20 to 40 feet (6-12m) above the derrick floor, The Derrickman or another crew member works on the board while casing is being run in a well. The board may be wooden or fabricated of steel girders floored with anti-skid material and powered electrically to be raised or lowered to the desired level. A stabbing board serves the same purpose as a monkey board but is temporary instead of permanent.

ã DTL 2001 – Rev 2

GLOSSARY

stabiliser n: 1. a tool placed near the bit, and often just above it, in the drilling assembly and used to change the deviation angle in a well by controlling the location of the contact point between the hole and the drill collars. Conversely, stabilisers are used to maintain correct hole angle. See packed hole assembly. 2. a vessel in which hydrocarbon vapours are separated from liquids. 3. a fractionation system that reduces the vapour pressure so that the resulting liquid is less volatile. stack n: 1. a vertical pile of blowout prevention equipment. Also called preventer stack. See Blowout Preventer. 2. The vertical chimney-like installation that is the waste disposal system for unwanted vapour such as flue gases or tail-gas streams. stack a rig v: to store a drilling rig upon completion of a job when the rig is to be drawn from operation for a time. stand n: the connected joints of pipe racked in the derrick or mast during a trip. The usual stand is 90 feet long (about 27m), which is three lengths of drill pipe screwed together (a treble). standard cubic foot n: a gas volume unit of measurement at a specific temperature and pressure. The temperature and pressure may be defined in the gas sales contract or by reference to other standard. Its abbreviation is scf. standard pressure n: the pressure exerted by a column of mercury 760 mm high; equivalent to 14.7 psia. standard temperature n: a predetermined temperature used as a basic measurement. The petroleum industry uses 60ºF (15.5ºC) as its standard temperature during measurement of oil. The volume of a quantity of oil at its actual temperature (assuming it is not 60ºF) is converted to the volume the oil would occupy at 60ºF. Conversion is aided by the use of API conversion tables. standard well kill procedure n: any of industry’s proven techniques to control a flowing well wherein well control is obtained through pumping drilling fluid of increased density at a predetermined pumping rate with Blowout Preventer(s) closed and simultaneously controlling casing and drill pipe surface pressures by varying choke manifold choke settings until the well is stable and static with zero surface pressure. (API Recommended Practice 64). standpipe n: a vertical pipe rising along the side of the derrick or mast, which joins the discharge line leading from the fluid pump to the rotary hose and through which fluid is pumped going into the hole. starboard n: (nautical) the right side of a vessel (determined by looking toward the bow). steel-tooth bit n: a roller cone bit which the surface of each cone is made up of rows of steel teeth. Also called a milled-tooth bit or milled bit. still drilling assembly n: also called packed-hole assembly. See packedhole assembly. straight hole n: a hole that is drilled vertically. the total hole angle is restricted, and the hole does not change direction rapidly – no more than 3º per 100 feet (30.48 m) of hole. straight-through function n: a subsea function that is directly operated by a pilot signal without interface with a pod mounted pilot operated control valve. Straight-through functions typically require a low fluid volume to operate and the response time is not critical. (API Recommended Practice 16E)

ã DTL 2001 – Rev 2

stress relief n: controlled heating of material to a predetermined temperature for the purpose of reducing any residual stresses after welding. (API Specification 16A) strip a well v: to pull rods and tubing from a well at the same time – for example, when the pump is stuck. Tubing must be stripped over the rods a joint at a time, and the exposed sucker rod is then backed off and removed. stripper head n: a blowout prevention device consisting of a gland and packing arrangement bolted to the well head. It is often used to seal the annular space between the tubing and casing. stripping in v: 1. the process of lowering the drill stem into the well bore when the well is shut in on a kick. 2. the process of putting tubing into a well under pressure. strip pipe v: 1. to remove the drill stem from the hole while the Blowout Preventers are closed. 2. to pull the drill stem and the wash over pipe out of the hole at the same time. structural casing n: the outer string of large diameter, heavy-wall pipe installed in wells drilled from floating installation to resist the bending movements imposed by the marine riser, and to help support the wellhead installed on the conductor casing. (API Recommended Practice 64) stuck pipe n: drill pipe, drill collars, casing, or tubing having inadvertently become immovable in the hole. Sticking may occur when drilling is in progress, when casing is being run in the hole, or when the drill pipe is being hoisted. stuck point n: the depth in the hole at which the drill stem, tubing, or casing is stuck. studded connections n: connections in which thread-anchored studs are screwed into tapped holes. (API Specification 16A) stuffing box n: a packing gland screwed in the top of the well head through which the polished rod operates on a pumping well. It prevents the escape of oil, diverting it into a side outlet to which is connected the flow line, leading to the oil and gas separator or the field storage tank. subsea blowout preventer n: a Blowout Preventer placed on the sea floor for use by a floating offshore drilling rig. subsea test tree n: a device designed to be landed in a subsea well head or Blowout Preventer stack to provide a means of closing in the well on the ocean floor so that a drill stem test of an offshore well can be obtained. subsurface safety valve n: a device installed in the production tubing in a well below the well head and designed to prevent uncontrolled well flow when actuated. These devices can be installed and retrieved by wireline (wireline retrievable) and pump down methods, or be an integral part of the tubing string (tubing retrievable). (API Recommended Practice 57) suction pit n: also called a suction tank, sump pit, or fluid suction pit. suction tank n: the fluid tank from which fluid is picked up by the suction of the fluid pumps. sulphate-reducing bacteria n: bacteria that digest sulphate present in water, causing the release of hydrogen sulphide, which combines with iron to form iron sulphide, a troublesome scale.

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GLOSSARY

supercharge v: to supply a charge of air to the intake of an internalcombustion engine at a pressure higher than that of the surrounding atmosphere.

swivel n: a rotary tool that is hung from the rotary hook and travelling block to suspend and permit free rotation of the drill stem. It also provides a connection for the rotary hose and a passageway for the flow of drilling fluid into the drill stem.

surface casing n: also called surface pipe. surface-motion compensator n: a heave compensator.

swivel packing n: special rubberised compounds placed in a swivel to prevent drilling fluid from leaking out under high pressure.

surface pressure n: pressure measure at the well head.

t sym: tonne

surface safety valve n: a Christmas tree valve and actuator assembly designed to prevent uncontrolled well flow when actuated. (API Recommended Practice 57)

tail pipe n: 1. a pipe run in a well below a packer. 2. pipe used to exhaust gases from the muffler of an engine to the outside atmosphere.

surge n: 1. an accumulation of liquid above a normal or average level, or a sudden increase in its flow rate above a normal flow rate. 2. the motion of a mobile offshore drilling rig in a direction in line with the centre line of the rig, especially the front-to-back motion of the rig when it is moored in a sea-way. surge effect n: a rapid increase in pressure down hole that occurs when the drill stem is lowered rapidly or when the fluid pump is quickly brought up to speed after speeding. surging n: a rapid increase in pressure down hole that occurs when the drill stem is lowered too fast or when the fluid pump is brought up to speed after starting. swab n: a hollow, rubber-faced cylinder mounted on a hollow mandrel with a pin joint on the upper end to connect to the swab line. A check valve that opens upward on the lower end provides a way to remove the fluid from the well when pressure is insufficient to support flow. v: to operate a swab on a wireline to bring well fluids to the surface when the well does not flow naturally. Swabbing is temporary operation to determine whether or not the well can be made to flow. If the well does not flow after being swabbed, pump is installed as a permanent lifting device to bring the oil to the surface. swab valve n: the uppermost valve in vertical line on the Christmas tree, always above the flow-wing valve. (API Recommended Practice 57) swabbed show n: formation fluid that is pulled into the well bore because of an underbalance of formation pressure caused by pulling the drill string too fast. swabbing effect n: phenomenon characterised by formation fluids being pulled or swabbed into the well bore when the drill stem and bit are pulled up the well bore fast enough to reduce the hydrostatic pressure of the fluid below the bit. If enough formation fluid is swabbed into the hole, a kick can result. sweet crude oil n: oil containing little or no sulphur, especially little or no hydrogen sulphide. sweet gas n: gas that has no more than the maximum sulphur content defined by (1) the specifications for the sales gas from a plant or (2) the definition by a legal body such as the Railroad Commission of Texas. switchable three-way target valve n: a device having an erosion resistant target with changeable position to enable selection of flow direction of diverted well fluids. (API Recommended Practice 64)

take out v: to remove a joint or stand of pipe, casing, or tubing that is to be run in a well. tapered string n: drill pipe, tubing, sucker rods, and so forth with a diameter near the top of the well larger than the diameter below. tar sand n: a sandstone that chiefly contains very heavy, tar like hydrocarbons. Tar sands are difficult to produce by ordinary methods; thus it is costly to obtain usable hydrocarbon from them. target n: a bull plug or blind flange at the end of a tee to prevent erosion at a point where change in flow direction occurs. (API Recommended Practice 53) targeted n pl: refers to a fluid piping system in which flow impinges upon a lead-filled end (target) or a piping tee when fluid transits a change in direction. (API Recommended Practice 59) telescoping joint n: a device used in the marine riser system of a mobile offshore drilling rig to compensate for the vertical motion of the rig caused by wind, waves, or weather. It consists of an inner barrel attached beneath the rig floor and an outer barrel attached to the riser pipe and is an integrated part of the riser system. telescopic (slip) joint packer n: a torus-shaped hydraulic or pneumatically actuated, resilient element between the inner and outer barrels of the telescopic (slip) joint which serves to retain drilling fluid inside the marine riser. telltale hole n: a hole drilled into the space between tings of packing material used with a liner in a fluid pump. When the liner packing fails, fluid spurts out of the telltale hole with each stroke of the piston, indicating that the packing must be renewed. temporary guide base n: the initial piece of equipment lowered to the ocean floor once a mobile offshore drilling rig has been positioned on location. It serves as an anchor for the guidelines and as a foundation for the permanent guide base and has an opening in the centre through which the bit passes. It is also called a template. tensile strength n: the greatest longitudinal stress that a metal can bear with out tearing apart. Tensile strength of a metal is greater than yield strength. tensioner system n: a system of devices installed on a floating offshore drilling rig to maintain a constant tension on the riser pipe despite any vertical motion made by the rig. The guidelines must also be tensioned, and a separate tensioner system is provided for them. Texas deck n: the main load-bearing deck of an offshore drilling structure and the highest above the water, excluding auxiliary decks such as the helicopter landing pad.

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ã DTL 2001 – Rev 2

GLOSSARY

thermometer n: an instrument that measures temperature. Thermometers provide a way to estimate temperature from its effect on a substance with known characteristics (such as a gas that expands when heated). Various types of thermometers measure temperature by measuring the change in pressure of a gas kept at a constant volume, the change in electrical resistance of metals, or the galvanic effect of dissimilar metals in contact. The most common thermometer is the mercury-filled glass tube that indicates temperature by the expansion of the liquid mercury.

tour n: (pronounced “tower”) a working shift for drilling crew or other oil field workers. The most common tour is 8 hours long; the three daily tours are called daylight, evening, and graveyard (or morning). Sometimes 12-hour tours are used, especially on offshore tigs; they are called simply day tour or night tour. toxic substance n: a substance or material which can be detrimental to human health or the functional capacity of a person having exposure to it. (API Recommended Practice 57)

thermostat n: a control device used to regulate temperature. thief formation n: a formation that absorbs drilling fluid as the fluid is circulated in the well; also called a thief sand or a thief zone. Lost circulation is cause by a thief formation. thixotropic n: the property exhibited by a fluid that is in a liquid state when flowing and in a semisolid, gelled state when at rest. Most drilling fluids must be thixotropic so that the cuttings in the fluid will remain in suspension when circulation is stopped. tie-back string n: casing that is run from the top of a liner to the surface. A tie-back string is often used to provide a production casing that has not been drilled through. tight formation n: a petroleum or water-bearing formation of relatively low porosity and permeability. tight hole n: 1. a well about which information is restricted for security or competitive reasons and such information given only to those authorised to receive it. 2. a section of the hole that, for some reason, is under-gauge. For example, a bit that is worn under-gauge will drill a tight hole. tight spot n: a section of a borehole in which excessive wall cake has built up, reducing the hole diameter and making it difficult to run the tools in and out. Compare key seat. ton n: 1. (nautical) a volume measure equal to 100 ft³ applied to mobile offshore drilling rigs. 2. (metric) a measure of weight equal to 1000 kg. Usually spelled tonne. tonne n: a mass unit in the metric system equal to 1000 kg. tool joint n: a heavy coupling element for drill pipe, made of special alloy steel. Tool joints have coarse, tapered threads and seating shoulders designed to sustain the weight of the drill stem, withstand strain of frequent coupling and uncoupling, and provide a leak-proof seal. the male section of the joint, or the pin, is attached to one end of the drill pipe, and the female section, or the box, is attached to the other end. The tool joint may be welded to the end of the pipe, screwed on, or both. a hard-metal facing is often applied in a bas around the outside of the tool joint to enable it to resist abrasion from the wall of the borehole. torqu n: the turning force that is applied to a shaft or other rotary mechanism to cause it to rotate or tend to do so. Torque is measure in units of length and force (foot-pounds, Newton-metres). torque indicator n: an instrument that measures the amount of torque (turning or twisting action) applied to the drill or casing string. The amount of torque applied to the string is important when joints are being made up. torque recorder n: an instrument that measures and makes a record of the amount of torque (turning or twisting action) applied to the drill or casing string.

traceability, job lot n: the ability for parts to be identified as originating from a job lot which identifies the included hear(s). (API Specification 16A) transducer n: a device actuated by power from one system and supplying power to another system, usually in a different form. For example, a telephone receiver receives electric power and supplies acoustic power. tricone bit n: a type of bit in which three cone shaped cutting devices are mounted in such a way that they intermesh and rotate together as the bit drills. The bit body may be fitted with nozzles, or jets, through which the frilling fluid is discharged. A one-eye bit is used in soft formations to drill a deviated hole. trip n: the operation of hoisting the drill stem out and returning it to the well bore. v: shortened form of “make a trip”. See make a trip. tripping v: the operation of hoisting the drill stem out of and returning it to the well bore; making a trip. See trip. trip gas n: an accumulation of gas which enters the hole while a trip is made. (API Recommended Practice 53) trip margin n: an incremental increase in drilling fluid density to provide an increment of overbalance in order to compensate for effects of swabbing. (API Recommended Practice 59) trip tank n: a small fluid tank with a capacity of 10 to 15 bbl, usually with 1-bbl divisions, used exclusively to ascertain the amount of fluid necessary to keep the well bore full with the exact amount of fluid equal to that which the drill pope occupied while in the hole must be pumped into the hole, the drill pipe displaces a certain amount of fluid, and a trip tank again can be used to keep track of this volume. true vertical depth n: the depth of a well measure from the surface straight down to the bottom of the well. The true vertical depth of a well may be quite different from its actual measured depth, because wells are very seldom drilled exactly vertical. tubing n: small-diameter pipe that is run into a well to serve as a conduit for the passage of oil and gas to the surface. tubingless completion n: a method of completing a well in which a small diameter production is set through the producing zone with no tubing or inner production string employed to bring formation fluids to the surface. (API Recommended Practice 57) tubular goods (tubular) n pl.: any kind of pipe; also called tubulars. Oil field tubular goods include tubing, casing, drill pipe, and line pipe. tungsten carbide bit n: a type of roller cone bit with inserts made of tungsten carbide. Also called tungsten carbide insert bit.

total depth n: the maximum depth reached in a well.

ã DTL 2001 – Rev 2

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GLOSSARY

tungsten carbide insert bit n: also called tungsten carbide bit. See tungsten carbide bit.

vacuum n: 1. theoretically, a space that is devoid of all matter and that exerts zero pressure. 2. a condition that exists in a system when pressure is reduced below atmospheric pressure.

turbine motor n: usually called a turbodrill. see turbodrill. turbodrill n: a drilling tool that rotates a bit that is attached to it by the action of drilling fluid on the turbine blades built into the tool. When a turbodrill is used, rotary motion is imparted only at the bit; therefore, it is unnecessary to rotate the drill stem. Although straight holes can be drilled with the tool, it is used most often in directional drilling. turbulent flow n: the flow of a fluid in an erratic, non-linear motion, caused by velocity. TVD abbr.: true vertical depth. twist-off n: a complete break in pipe caused by rotational force wrenching damaged pipe apart. twist off v: to part or split drill pipe or drill collars, primarily because of metal fatigue in the pipe or because of mishandling. ullage n: the amount by which a tank or a vessel comes short of being full, especially on ships. Ullage in a tank is necessary to allow space for the expansion of the oil in the tank when the temperature increases. Also called outage umbilcal n: a line that supplies a diver or a diving bell with a lifeline, a breathing gas, communications, a pneumo-fathometer, and if needed, a heat supply. under-balance n: the amount by which formation presser exceeds pressure exerted by the hydrostatic head of fluid in the well bore. (API Recommended Practice 59) unconsolidated sandstone n: a sand formation in which individual grains do not adhere to one another. If an unconsolidated sandstone produces oil or gas, it will produce sand as sell, if not controlled or corrected.

vacuum degasser n: a device in which gas-cut fluid is degassed by the action of a vacuum inside a tank. The gas-cut fluid is pulled into the tank, the gas removed, and the gas-free fluid discharged back into the fluid tank. vapour n: a substance in the gaseous state, capable of being liquefied by compression or cooling. V-door n: an opening at floor level in a side of a derrick or mast. The v-door is opposite the draw-works and is used as an entry to bring in drill pipe, casing, and other tools from the pipe rack. The name comes from the fact that on the old standard derrick, the shape of the opening was an inverted V. vent n: an opening in a vessel, line, or pump to permit the escape of air or gas. vent line n: the conduit which directs the flow of diverted well bore fluids away from the drill floor to the atmosphere. (API Recommended Practice 64) vent line valve n: a full-opening valve which facilitates the shut off of flow or allows passage of diverted well bore fluids through the vent line. (API Recommended Practice 64) vent outlet n: the point at which fluids exit the well bore below the annular sealing device via the vent line. (API Recommended Practice 64) venturi effect n: the drop in pressure resulting from the increased velocity of a fluid as it flows through a constricted section of a pipe. vertical n: an imaginary line at right angles to the plane of the horizon. adj.: of a well bore, straight, not deviated.

underground blowout n: an uncontrolled flow of gas, salt water, or other fluid out of the well bore and into another formation that the well bore has penetrated.

viscosity n: a measure of the resistance of a liquid to flow. Resistance is brought about by the internal friction resulting from the combined effects of cohesion and adhesion. The viscosity of petroleum products is commonly expressed in terms of the time required for a specific volume of the liquid to flow through an orifice of a specific size.

upper kelly cock n: the kelly cock, as distinguished from the drill stem safety valve, sometimes called the lower kelly cock. See kelly cock.

visual examination n: examination of parts and equipment for visible defects in material and workmanship. (API Specification 16A)

upset v: to forge the ends of tubular products so that the pipe wall acquires extra thickness and strength near the end. Usually upsetting is performed to provide the thickness needed to form threads so that the tubular goods can be connected. n: the thickened areas formed by upsetting of tubular goods.

voids n pl.: cavities in a rock that do not contain solid material but may contain fluid.

upstream adv.: in the direction opposite the flow in a line. n: the point in a line or system situated opposite the direction of flow. usable hydraulic fluid n: the hydraulic fluid volume recoverable from the accumulator system between the maximum designed accumulator operating pressure and the minimum operating pressure. (API Recommended Practice 16E) U-tube n: a U-shaped tube. U-tubing n: the action of fluids flowing in a U-tube (as heavy fluid forcing lighter down the drill stem and up the annuls).

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volumetric efficiency n: actual volume of fluid put out by a pump, divided by the volume displaced by a piston or pistons (or other device) in the pump. Volumetric efficiency is usually expressed as a percentage. For example, if the pump pistons displace 300 cubic inches, but the pump puts only 291 cubic inches per stroke, then the volumetric efficiency of the pump is 97 percent. volumetric non-destructive examination v: examination for internal material defects by radiography acoustic emission or ultrasonic testing. (API Specification 16A) wait-and-weight method n: a well-killing method in which the well is shut in and the fluid weight is raised the amount required to kill the well. The heavy fluid is then circulated into the well, while at the same time the kick fluids are circulated out. So called because one shuts the well in and waits for the fluid to be weighted before circulation begins.

ã DTL 2001 – Rev 2

GLOSSARY

wall cake n: also called filter cake or fluid cake. See fluid cake. wall sticking n: differential-pressure.

also called differential-pressure sticking.

See

washout n: 1. excessive well bore enlargement caused by solvent and erosive action of the drilling fluid. 2. a fluid-cut opening caused by fluid leakage. water-base hydraulic fluid n: control fluid mixture composed of water soluble lubricant and water. (API Recommended Practice 16E) water-base fluid n: a drilling fluid in which the continuous phase is water. In water-base fluids, any additives are dispersed in the water. Compare oil-base fluid. weight cut n: the amount by which drilling fluid density is reduced by entrained formation fluids or air. (API Recommended Practice 59) weight indicator n: an instrument near the driller’s position on a drilling rig. It shows both the weight of the drill stem that is hanging from the hook (hook load) and the weight that is placed on the bit by the drill collars (weight on bit). weighting material n: a material that has a high specific gravity and is used to increase the density of drilling fluids or cement slurries. weight on bit n: the difference between the net weight of the entire drill stem and the reduced weight resulting when the bit is resting on bottom. weight up v: to increase the weight or density of drilling fluid by adding weighting material. weld, fabrication n: a weld joining two or more parts. (API Specification 16A) weld, non pressure containing n: a weld, the absence of which will not reduce the pressure-containing integrity of the component. (API Specification 16A) weld, pressure containing n: a weld, the absence of which will reduce the pressure-containing integrity of the component. (API Specification 16A)

WellCAP abbr.: an accredited “well control” training programme developed by the International Association of Drilling Contractors to ensure a minimum standard of training of personnel employed by member companies. well control n: the methods used to prevent a well from blowing out. Such techniques include, but are not limited to, keeping the borehole completely filled with drilling fluid of the proper weight or density during all operations, exercising reasonable care when tripping pipe out of the hole to prevent swabbing, and keeping careful track of the amount of fluid put into the hole to replace the volume of pipe removed from the hole during a trip. wellhead n: the equipment installed at the surface of the well bore. A well head includes such equipment as the casing head and tubing head. adj.: pertaining to the well head (e.g. well head pressure). wellhead connector (stack connector) n: a hydraulically operated connector that joins the BOP stack to the subsea well head. (API Recommended Practice 16E) wild well n: a well that has blown out of control and from which oil, water, or gas is escaping with great force to the surface; also called a gusher. wireline operations n pl.: operations performed in a well bore by use of tools which are run and pulled on small diameter slick, braided or electric wireline. (API Recommended Practice 57) wireline preventers n pl: preventers installed on top of the well or drill string as a precautionary measure wile running wireline. The preventer packing will close around the wireline. (API Recommended Practice 59) wireline well logging n: the recording of subsurface characteristics by wireline tools. Wireline well logs include acoustic logs, calliper logs, radioactivity logs and resistivity logs. WOR abbr.: water-oil ratio. working pressure n: the maximum pressure at which an item is to be sued as a specified temperature. wireline preventer n: preventers installed on top of the well or drill string as a precautionary measure while running wireline. The preventer packing will close around the wireline. (API Recommended Practice 53)

weld groove n: an area between two metals to be joined that has been prepared to receive weld filler metal. (API Specification 16A)

working pressure rating n: the maximum pressure at which an item is designed for safe operation. (API Recommended Practice 64)

weld joint n: a description of the way components are fitted together in order to facilitate joining by welding. (API Specification 16A)

yield point n: the maximum stress that a solid can withstand without undergoing permanent deformation either by plastic flow or by rupture. See tensile strength.

welding v: the fusion of metals with or without the addition of tiller materials. (API Specification 16A)

yield strength n: the stress level measure at room temperature, expressed in pounds per square inch of loaded area, at which material plastically deforms and will not return to its original dimensions when the load is released. All yield strengths specified in this standard shall be considered as being 0.2% yield offset strength per ASTM A370. (API Specification 16A)

well n: the hole made by the drilling bit, which can be open, cased, or both. Also called well bore, borehole, or hole. well bore n: a borehole, the hole drilled by the bit. A well bore may have casing in it or it may be open (uncased); or a portion of it may be cased, and a portion of it may be open. Also called a borehole or hole.

ã DTL 2001 – Rev 2

zone n: a term used to distinguish different rock strata (e.g shale zone, sand zone, pay zone, etc). (API Recommended Practice 57)

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GLOSSARY

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ã DTL 2001 – Rev 2