Rotary Drilling

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The On-line

Mud Logging

Handbook

by Alun Whittaker

See Acrobat Document Properties (in the Acrobat Reader > File menu) for publication and revision dates

Rotary Drilling

Aegis Group

244 Ohio Street

Vallejo, CA 94590-5051

USA

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Rotary Drilling

A mud engineer will tell you that well cuttings only contaminate his perfect drilling fluid, while a mud logger will say drilling mud – any drilling mud – ruins all well cuttings.

A driller will tell you that both – mud and cuttings – get in the way of him makin' hole, and muck up his boots. In this chapter, we'll look at the process of making the hole that to exist before we can do our job. Plus how can we learn useful things from watching (and listening to) the driller, and how in return we can help him do his job.

✔ The rotary drilling rig

✔ Components of the drill string: drill pipe, drill collars, drilling tools, and types of drill bit ✔ Drilling mud chemistry; water-, oil-, and gas-based drilling fluids and processes ✔ Bore-hole fluid circulation: fluid density, viscosity, flow regimes, and carrying capacity

✔ Bore-hole fluid pressures: density and hydrostatic head, mud flow pressure losses, and hydraulics ✔ Well pressure control: drilling fluid balance, under- and overbalance, well heads and control equipment ✔ Cutting sampling from mud, coring on the drill string or wire line.

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Chapter Summaries

, and fine a better place to start, or use the

Index

to search for the subject you need.

List of Figures & Tables

Figure 1: A modern rotary drilling rig and the well-bore beneath it. Drilled formation cuttings, oil, water and gas samples are recovered to surface with the circulating drilling fluid. ...10 Figure 2: The circulating system for a liquid-based drilling fluid - drilling mud. The solids control equipment provides the best locations for cuttings, fluid sampling equipment and sensors. ...13 Figure 3: A modern double-decked shale shaker. Cuttings are removed as the drilling mud passes through the upper vibrating coarse

screen. Finer, unconsolidated material, and contaminants are removed by the lower fine screen (Illustration courtesy of Baroid, Inc.). ...14 Figure 4: The de-sander and de-silter are larger and smaller hydroclones. In this de-sander, drilling fluids travels upward in a helical path, as fine mud solids are thrown out into the drain water. The de-silter uses smaller hydroclones and mud rapid mud flow, to remove even finer solids (Illustration courtesy of Baroid, Inc.). ...15 Figure 5: The most important components of the drill string are the joints of drill pipe and drill collars. ...17 Figure 6: The bottom hole assembly provides directional control to the drill bit, and is made up of drill collars, stabilizers and reamers...18 Figure 7: Are short sections of pipe in the drill string. They perform various specialized functions in controlling drilling. Some examples are shown here. ...19 Figure 8: Drill rate depends on the bit type, size, weight applied by the drill collars, the rotating speed and mud hydraulics. If these are known then other changes in rate of penetration may be interpreted as changes in rock strength, porosity, induration, or fracturing. ...21 Figure 9: Howard Hughes tri-cone bit design introduced the concept of three self-cleaning, inter-meshing cones...22 Figure 10: The tri-cone rock was developed in the 1930’s. Enhancements Included jet nozzles, sealed bearings, tooth hard-facing and sintered tungsten carbide inserts ...23 Figure 11: Drill string torque measured at surface reflects the resistance to rotation of the drill bit. Formation strength and consistency may be deduced from the magnitude and variability of torque. ...24

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

courtesy Eastman-Christensen)...25

Figure 13: The earliest rotary drill bit design was the drag bit which sheared and scraped soft rocks and sediments much like the action of a wood chisel on a lathe...26

Figure 14: The earliest drag or fishtail drill bit designs were later revived with the innovation of poly-crystalline diamond compact (PDC or “Stratapax”) drilling blanks in place of steel cutting blades. PDC bits offer long bit life coupled with high rates of penetration (Illustration courtesy Diamant-Boart Stratabit)...27

Figure 15: The guide shoe provides a smooth nose to assist the casing string in reaching the bottom of the hole...33

Figure 16: Components added to the casing string to ensure complete and well-bonded cementation...34

Figure 17: The float collar separates the cement and drilling fluid and prevents flow into and out off the casing string...35

Figure 18: The Cement Plugs separate the cement slurry from the drilling fluid and signal important events in the cementing of the casing string...36

Figure 19: A graphical example of a bore-hole profile. ...39

Figure 20: A Table of capacities and displacements of some common sizes of drill pipe, drill collars, and casing...43

Figure 21: Hydrostatic pressure of the drilling fluid has an important effect on the efficiency and consistency with which cuttings are removed from beneath the drill bit cutting structure. ...44

Figure 22: Flow rate and flow regime of the drilling fluid effect the efficiency and consistency with which cuttings are recovered to surface. 46 Figure 23: Mud Balance (Illustration courtesy Magcobar Div., Dresser Industries)...50

Figure 24: Marsh Viscosity Funnel (Illustration courtesy Magcobar Div., Dresser Industries)...51

Figure 25: Fann V-G Meter (Illustration courtesy Magcobar Div., Dresser Industries)...52

Figure 26: The circulation system required for a gas-based drilling fluid system: gas (usually compressed air), mist or foam. ...57

Figure 27: The Core Bit or Core Head is Similar in Design to a Diamond or P,D.C. Drill Except for the Central Opening for Entry of the Core into the Core Barrel (after Christensen Diamond Products, used with permission) ...59

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Figure 28:The Conventional and wire-line recoverable core barrels are similar in design and function. ...60

Figure 29: Inner-sleeved core barrels can be used to improve core recovery from fractured, unconsolidated, or very brittle rocks likely to broken, jammed or lost from the core barrel...62

Figure 30: In the oriented core barrel, a steel blade scribes a groove on the core as it enters the barrel. Later, the scribe line on the core can be aligned with drilling depth and bore-hole directional measurements...64

Figure 31: The foam-lined and pressurized core barrels offer a way to capture or retain formation fluids from the cored formation when it is returned to surface. ...65

Figure 32: The Chronological Sample Taker (CST) or wire-line sidewall coring tool. ...67

Figure 33: The Hard Rock Coring Tool (HRCT) or rotary sidewall corer ...68

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Rotary Drilling

Makin' Hole

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

The Drilling Rig

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

The drilling derrick stands on the rig floor or drill floor. This is essentially a large table supporting the tower, hoisting and rotating components. The height of the drill floor above the

ground (or deck of an offshore platform or drill ship) allows access to the casing head, blowout preventers and other circulation components. This area, below the rig floor is called the cellar (on an onshore rig) or the moon-pool (offshore).This can all be seen in Figure 1.

Hoisting Components

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

First time at the well site? Then one of the first things you will learn is

that the tall

tower

that dominates every view of the rig is rarely referred

to as the tower. Usually, it is called the

derrick

or the

m ast

.

Then, you will learn that the 8 or 12-hour work shift on the rig is

commonly referred to as a

tour

, but that word is pronounced like

tower

. So if you're told to be there for (what sounds like) the

graveyard

tower

, plan on arriving at midnight for the late night--early morning

work shift.

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

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The Deadline Anchor

This is clamp holding the fixed end of the drilling line. Periodically, this is un-clamped so that fresh drilling line can be spooled from a storage drum into the hoisting system to replace old line that has reached it’s acceptable limit of tonne-miles.:

The section of drilling line from this anchor to the top of the drilling mast is called the deadline. It is on this section that strain gauge sensors are placed to measure weight hanging from the hoisting system. Measurement of strain in the deadline can be calibrated in thousands of kilograms (or pounds) of hook-load hanging from the drilling hook. When the drill bit is resting on bottom, then the reduction of hanging weight indicates the weight on bit (WOB) being applied to push the drill bit ahead.

Blocks

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

Draw Works

After the last turn over the crown block, the drilling line runs down to the draw works, a large powered drum on the opposite side of the tower from the deadline anchor. This section of the drilling line is called the fast line.

The driller’s station is usually beside the draw works. Here, he has a large weight indicator displaying the hook-load and weight on bit (along with other measurements) and a long brake handle that he uses to control the lifting and lowering of the traveling block. He may also have other instruments displaying the total depth and rate of penetration computed from movement of the traveling block.

Rotating Components

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

Rotary Table

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

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

Top Drive

On many modern rigs, the rotary table has been dispensed with. Instead, a top drive or power sub is suspended from the drilling hook and rotates the top end of the kelly or of the drill string directly.

Rotary speed and drilling torque measurements are taken and used in a similar way.

Down-hole Motor

When solid-bodied drill bits are used (commonly diamond and PDC bits — see below) the best rates of penetration can be obtained by supplying the highest possible rates of penetration. These can be obtained using a down-hole motor.

Getting very high rotary speeds with a rotary table or top drive, requires supplying great amounts of energy, much of which is dissipated overcoming frictional effects of the rotating drill string in the well bore. This friction may also lead to excessive wear and risk of damage to the drill string or well casing (steel pipe used to line upper sections of the well bore).

When such bit types are used, they often accompanied by a hydraulically powered turbine or Moinneau-type positive displacement motor installed in the drill string, just above the bit, and powered by the circulating drilling fluid.

In such circumstances, the drill string may still be rotated slowly to help prevent sticking problems of stationary drill pipe.

Circulating Components

At the top of the drill string, the kelly or top drive incorporate a rotating, high pressure swivel allowing the drill string to be rotated while drilling fluid is pumped into the drill string. The drilling fluid passes from the kelly swivel, through the rotating kelly, drill pipe, drill collars and eventually to the drill bit (see Figure 2).

The circulating drilling fluid, which may be a liquid, gas or any combination of these, serves to cool and lubricate the rotating drill string, to clean the drill bit and carry rock cuttings back to surface. It also provides a hydrostatic head to balance formation fluid pressures and prevent a well blowout. In some ultra- deep or non-vertical wells, and when using diamond or PDC drill bits, the fluid may also power the drilling process by rotating a turbine or Moinneau-type drilling motor located in the drill string near the bit.

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

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The drilling fluid returns to surface through the annulus: the space between the outer bore hole wall and the inner rotating drill string. Through the lowermost recently drilled portion of the annulus, the drilling fluid and its load of drill cuttings is exposed to previously drilled formations and fluids. Shallower formations are protected by casing: large diameter steel pipe which is run and cemented into the bore hole. Attached to the top of the casing is the blowout preventer stack. This is an assembly of several types of valves and seals that can close off the annulus or the entire well bore if control of subsurface pressures is lost.

Above the blowout preventers, the mud passes through a conductor pipe and flow line to the solids control equipment. This is where, according to the driller and mud engineer, the contaminants are removed from the drilling fluid. More correctly, as any geologist or mud logger will confirm, it provides their first opportunity to extract precious formation and fluid samples from the contaminating drilling mud. It is, of course, just a matter of priorities.

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

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The shale shaker is a vibrating mesh screen that removes the drill cuttings and other debris (see Figure 3). The drilling fluid drains from the flow line into a narrow tall tank at the rear of the shale shaker and

overflows from there onto the screen. This tank which is called the possum belly or, in Texas, the sow belly.

This is an ideal location for installing fluid samplers and other drilling mud sensors.

Figure 4: The de-sander and de-silter are larger and smaller hydroclones. In this de-sander, drilling fluids travels upward in a helical path, as fine mud solids are thrown out into the drain water. The de-silter uses smaller hydroclones

and mud rapid mud flow, to remove even finer solids (Illustration courtesy of Baroid, Inc.).

Regrettably, I am neither a veterinarian, nor a Texan, and so I am

unable to add any elucidation regarding either the origin, or the

aptness of these names.

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Passing through the vibrating shale shaker screen, the mud falls into a settling pit where finer material can settle out before the mud goes back to the mud pit to be mixed and conditioned in order to be returned to the bore hole. The well cuttings fall from the shale shaker screen into a drainage sump which is titled the reserve pit (on a modern rig, the term is a euphemism only, it is in fact a sealed waste pit,

periodically sucked out into a honey wagon and hauled away). Cuttings sample catching equipment can be located at this point. If the rig crew feel particularly favorably inclined toward mud loggers, there may also be a stairway and safety rail here.

The de-sander and de-silter do not operate continuously but are turned on by the Mud Engineer when he wishes to remove recirculating fine debris from the drilling mud that would otherwise cause abrasion of drilling equipment. Both devices are variants of the hydroclone. Drilling fluid flows in a helical path upward through the conical elements while water passes downwards (see Figure 4). Mud viscosity prevents mixing of the fluid flows while dense solid particles are thrown out of the mud and carried away by the water. As the name suggests, the de-silter, with smaller cones, promotes more rapid flow and therefore throws out finer solids material.

The fine grained material produced from the de-sander, de-silter ,and the lower screen of a double deck shale shaker do not usually represent fresh, whole cuttings but may be unconsolidated grains and abraded fragments that have been re-cycled through the bore hole several times. However, the devices must be sampled regularly, whenever they are running. This allows recognition of the typical material and can assist in locating and identifying newly encountered unconsolidated clastic sediments. significant detrital minerals or micro-fossils. For example: you have encountered a drilling break and asked the driller to pick up and circulate bottoms up. When the bottom hole sample is due to arrive you see nothing coming over the top screen of the shale shaker, but you do find a quantity of fine sand on the lower deck and the derrick man reports an increase in the volume of fine material being thrown out of the de-sander:

✔ Have the well penetrated an unconsolidated sandstone reservoir?

✔ Does the fine sediment now arriving in the mud look different in appearance from that seen previously? ✔ You have been looking, haven’t you?

The Drill String

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

Drill Pipe

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

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Drill Collars

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

Stabilizers

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

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

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

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

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✔ Bit and crossover subs are used to connect together components with different types and sizes of threaded pins and boxes. The bit sub may also contain a check (or one-way) valve allowing drilling fluid to be pumped down to through the bit to bottom, but to prevent any flow back up the inside of the drill string that may be caused by hydrostatic imbalance.

✔ Shock and bumper subs are gas-filled shock absorbers used to maintain constant weight on bit when drilling from a moving drill ship or floating drilling platform.

✔ A junk sub has small catcher pockets. The sub is run

immediately above a bit to catch lost bit cones or other heavy metal debris, thrown up by turbulence that, if left in place, may cause damage to later drill bits

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

Drill Bit

The lowermost item in the drill drill string, the drill bit is of critical interest to the mud logger. The rate at which the bit penetrates through the formation is controlled by mechanical operating parameters and by the physical strength of the formation. Instantaneous changes in the drill rate can indicate to the skilled geologist formation changes caused by variations in porosity, mineralogy and cementation even before

cuttings are seen (see Figure 8). Conversely, by understanding these relationships, the geologist can assist the drilling engineer in selecting the most suitable bit and operating parameters in order to maximize rate of penetration and bit life.

The drill bit is also the geologist’s sampling tool. Drill bits vary greatly in design, cutting action and therefore in the size, shape and nature of the drill cuttings that they produce.

The most common type of drill bit used in commercial drilling features the tri-cone rock bit design first used in the 1930’s. Rotary cutter drill bits, developed by Howard Hughes (senior) and others, used two, three or even four cylindrical rollers, but the modern tri-cone design was patented by the younger Howard Hughes (yes, him!) in 1934. This design (see Figure 9 ) uses three rotating cones with inter-meshing teeth. The rotating cones crush and gouge material from the bottom of the hole, and the inter-meshing of the teeth makes them

self-cleaning. In effect, each row of teeth on a cone crushes solid rock beneath the bit, and then rotates off-bottom to pick clean the crushed-rock debris in the gaps between the teeth of the adjacent cone.

When a junk sub is run, the mud logger should always be on hand

when it is tripped out of the hole. Although intended to recovered

metal fragments, it does sometimes capture fist- sized fragments of

drilled formation, giving a fresh appearing sample that should not

be missed.

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

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Figure 9: Howard Hughes tri-cone bit design introduced the concept of three self-cleaning, inter-meshing cones. For best effect in all rock types, the teeth may be (see Figure 10):

✔ Long, slender, and widely spaced for drilling formations with low cohesion, or

✔ Short and broad for drilling harder rocks. For longer life and abrasion resistance, the milled steel teeth may be hard-faced with abrasion-resistant material, or they may be replaced by inserts made of sintered tungsten carbide.

The shape and size of the rock cuttings produced by a tri-cone bit reflect the shape, length and spacing of the teeth on the cones. Long slender teeth produce large, freshly broken cuttings from soft rocks and sediments. Broad teeth and inserts produce smaller, more rounded, crushed and ground cuttings from hard rocks. The torque, or resistance to rotation of the drill bit is measured at surface and will, like rate of penetration, assist the geologist in identification of formation boundaries while drilling proceeds (see Figure 11).

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Figure 10: The tri-cone rock was developed in the 1930’s. Enhancements Included jet nozzles, sealed bearings, tooth hard-facing and sintered tungsten carbide inserts

Unfortunately, the tri-cone bit has numerous bearing surfaces and seals. As a result, both the cutting ability and cone tightness tend to deteriorate in only a short time and, with them, rate of penetration and cutting quality decline. tri-cone bits must be replaced regularly, every 10 to 50 hours, requiring the entire drill string to be pulled out of the hole with consequent time delay and risk of bore hole damage.

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

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

Figure 12: Diamond drill bits have the advantages of an extremely hard cutting structure and the absence of moving parts to wear out. They are also very expensive, tend to drill slowly and the crushed and burned diamond bit cuttings

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

Figure 13: The earliest rotary drill bit design was the drag bit which sheared and scraped soft rocks and sediments much like the action of a wood chisel on a lathe

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

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PDC drill bits, sometimes called Stratapax®_{or TSP}®_{(Thermally Stable Products), produce large, fresh sheared drill cuttings with little}

surface damage or mechanical deformation. They are also relatively cheap and drill very quickly in soft, medium and moderately hard formations. Unfortunately, they are unsuccessful in drilling the very hardest and most resistant rocks. In these formations or if they used with unsuitable drilling parameters, PDC bits can produce churned and ground cuttings almost as bad as those from a diamond bit.

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

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Most recently, several hybrid designs have been proposed involving PDC studded cones and rollers. These may, eventually, become the best solution to efficient drilling of very hard rocks.

The geological significance if rate of penetration, and relative performance of different drill bits is discussed again in Chapter 11:The Basic Mud Log. The mathematical treatment of drilling data to help optimize drill bit selection has full treatment in Chapter 12: Geo-pressure Engineering Logs.

Open Hole

Open hole is the lowermost section of the the bore hole: the section that has been most recently drilled, and which approximates to the size

of the drill bit in diameter.

The intent of mud logging is to examine and evaluate rock and fluid, foot-by-foot as is liberated, by the drill bit, at the bottom of the hole. In reality, oil, gas, water, and rock material from the entire open hole section is in constant interaction with the the circulating drilling fluid. This effect has to be considered when evaluating mud log data (see Chapter 11:The Basic Mud Log), and must be considered when designing drilling, drilling fluid programs (see Drilling Fluids, later in this chapter.)

Periodically, to protect open hole zones from contaminating each other, or to prevent bore hole collapse (see the discussion of formation pressures and flow in Chapter 12, Geo-pressure Engineering Logs ), it is necessary to set and cement steel casing to line the bore hole.

Cased Hole

The uppermost section of the bore hole is lined with steel casing, cemented in place to support it, to prevent pressure and fluid

communication between porous zones in the formations behind the casing. The casing provides a bore hole of known diameter for further operations, and to:

✔ Prevent collapse of the bore hole wall, and caving into the returning drilling fluid stream

✔ Provide a means of containing formation pressures, and intra-zone flow, by preventing fracturing of upper, weaker zones ✔ Provide a means for attaching surface, well control equipment: the wellhead, blowout preventers, and production equipment ✔ Confine production of fluids from different zones into the well bore, when testing, or in final production

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

✔ Blowout Preventer Stack and W ellhead ✔ Surface Casing

✔ Intermediate Casing ✔ Liner

✔ Production Casing

Conductor Pipe

The conductor serves as a conduit to raise the circulating fluid high enough to return the drilling fluid to the pit (see Figure 1). The conductor runs from the wellhead or blow out preventer stack up to the rig floor, terminating in a flared section (known as the bell nipple, and flared so that drill bits and other tools can be run into the well without hanging up on the top of the conductor pipe) just below the rotary table. From the side of the conductor, near to its top, a horizontal mud return line carries the returning drilling fluid to the shale shaker and mud pits.

Before initial drilling is completed, surface casing set, and the high pressure blowout preventers installed, a diverter, or low-pressure

annular preventer, is usually attached at the top of the conductor, allowing the bore hole to be partially closed off, and the overflowing fluid to be diverted into the return line, or to the reserve pit.

On an onshore well, or an offshore (fixed, or jack-up) platform, the conductor is usually a short, simple, section of pipe, only a few meters long, standing above the blowout preventer stack, in the cellar (on an onshore rig), or in the moon-pool (offshore). On a floating rig, or drill ship, the conductor may be much longer, running from the seabed-located wellhead, and blowout preventers, all the way to the surface. Much more than a simple pipe, this type of conductor may contain buoyancy chambers, telescopic joints, electrical, and hydraulic conduits for the remote control systems used to control the wellhead attachment, and operate the blowout preventers on the seabed.

Blowout Preventer Stack and Wellhead

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

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The wellhead also supports the well control equipment, beneath the rig floor (or on the seabed), that can be closed on the open hole, or around drill string to hold it in place and prevent uncontrolled fluid flow to surface: a well kick, or blowout. Types of blowout preventers include:

✔ Pipe Rams, designed to be hydraulically (or, in emergency, manually) closed around the size (outside diameter) of drill pipe in use.

Obviously, such appropriately-sized pipe rams will not be able to close around the larger diameter drill collars, or even the enlarged

external upsets of the drill pipe tool joints.

✔ Blind Rams, designed to be hydraulically (or, in emergency, manually) closed, and to entirely seal the entire (inside diameter of the)

uppermost string of casing. Blind rams are used to safely seal the bore hole, preventing any influx of fluids, when there is no drill string in place. For example, when round tripping, to replace a worn drill bit.

✔ Shear Rams are a variation of blind rams. As the name suggests, shear rams can be closed even when the drill string is in place,

cutting through (or shearing) the drill pipe, so that the bore hole can be completely sealed when a blowout has occurred.

✔ The Annular Preventer contains a flexible, sealing ring that can be hydraulically compressed vertically, so that it bulges inward to close off the bore hole, or any pipe or tool inside it. Under full compression, the annular preventer can close off the open bore hole. At lower compressions, it can close and seal around drill pipe (even the tool joints), drill collars, and even the square or hexagonal-shaped kelly (see Rotary Table, above). At slightly less than full compression, the annular pressure can allow the drill string to be carefully moved up and down, or even rotated, with a slight leakage of drilling fluid serving as a lubricant.

A gage, immediately below the blowout preventers, indicates the shut-in casing pressure, so that the rams are not opened with an unexpected, possibly uncontrollable pressure below.

Surface Casing

This the first permanent string of true casing run into the hole. In subsequent operations, the surface casing will serve as the base for the wellhead and blowout preventers, and as the hanger, and pressure seal for all later strings of casing,

The surface casing may be put in place by: ✔ Being driven, using a pile driver,

✔ Washed-down, by circulating water down through the casing and washing away loose sediment below,

✔ Actual drilling, with a large diameter drill bit, and circulating drilling fluid, or

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

Intermediate Casing

Most subsequent strings of casing serve the purpose of protecting shallower and deeper zones from communicating, contaminating, or damaging each other. They are usually referred to as intermediate, or protection casing. Most commonly, protection casing protects against loss of circulation in shallow formations when heavy mud densities are required to control pressures when for drilling deeper zones. On the other hand,

intermediate casing may also be set through shallow, abnormally high-pressured zones, so that the drilling fluid density can be reduced in order to

safely drill into deeper, normally pressured formations.

Commonly, after drilling to a planned depth, the bore hole is conditioned by circulating clean drilling fluid for some time. Then, the necessary open

hole wire-line logs (those measurements that cannot be made later, through the steel walls of casing) are run. After this, intermediate casing can be

run, cemented, and pressure tested.

Next, with the appropriate new drilling fluid composition mixed in the pits, and a smaller drill bit, drilling re-commences.

Liner

Liners are mostly used to provide a low-cost completion of a well. Unlike casing which is hung from the wellhead, and runs from the surface to a given depth, a liner is hung from a hanger-like device inside, and near to the bottom of, the previous string of casing.

Using a liner, deeper zones in the well may be production tested, in an entirely enclosed, known volume bore hole, without the expense of running an entire new casing string to surface. Depending on the eventual purpose of the well, liners may be installed in different ways. For example:

✔ Liners suspended from a hanger device inside the previous casing string may be cemented in place, or ✔ They may be suspended in the well without cementing, allowing later removal, or replacement, or

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

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Production Casing

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

in a producing well.

The Casing String

Running Tools

Running casing into the hole is little different from tripping a new drill bit and drill string into the hole except, of course, that everything is larger and usually heavier. It is necessary to remove the rotary table from the rig floor, and to replace the usual elevator, and tongs, used to

make-up (and break-out) drill pipe connections with much larger replacements.

In place of the kelly, separate circulating, or cementing heads are required to:

✔ Periodically fill the casing with drilling fluid, to prevent it collapsing under hydrostatic pressure ✔ Pump the cement slurry down inside the casing, when it is in place, and

✔ Pump drilling fluid down into the casing to displace the cement out into the annular space between the casing and the bore hole wall.

Casing

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

centimeters

✔ Linear weight, for example pounds per foot, or kilograms per meter

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

Although the casing specification is of no significance to formation evaluation,

it is usual for the casing size and weight be reported on the mud log, at the

appropriate depth (depth to the casing guide shoe). This is just part of the mud

logs role as a concise record of all activities on the well.

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Casing Collars

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

Guide Shoe

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

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

Centralizers and Scratchers

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

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As the casing string is run into the hole it is periodically rotated and reciprocated, allowing the centralizers and scratchers to scrape the wall of the bore hole, removing mud filter cake (see Drilling Fluids, later in this chapter). This improves the quality of the bond to formed by the cement and the bore hole wall.

When the casing string is finally in place, the centralizers (at the right, in Figure 16) have a second function. They fix the casing string centrally in the bore hole and ensure uniform cement placement all around it.

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

Float Collar

The float collar is an alternative casing collar inserted between two joints of casing, near to the bottom of the bottom of the casing string. It incorporates a one-way valve (made of an easily drillable material) and performs a number of functions while the casing string is being run and cemented:

✔ While the casing is being run into the hole, the float collar works like a blowout preventer, preventing drilling fluid, or formation fluids from entering the casing string, and flowing to surface.

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✔ By keeping out dense drilling fluid, the float collar effectively reduces the weight of the casing string allowing it to float to bottom. This reduces strain on the surface hoisting gear.

However, empty casing may also be collapsed by external hydrostatic pressure, so some drilling fluid (or water) may need to be added from the top of casing string using a circulating head.

✔ The float collar serves as a stop for the top and bottom cement plugs used to separate drilling fluid and cement (see below).

✔ After the casing string is in place, and the cement slurry has been displaced out into the annulus, the float valve prevents the denser cement from flowing back into the casing string.

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

Note that the float collar is normally run a few joints of casing above the bottom of the casing string. If it

desired to run it

at

the bottom, then a combination float shoe (that is

float collar + guide shoe

) can be used.

A not relevant, but ver y useful tip:

the connections of regular casing collars are

doped with a friction-reducing pipe dope similar to that used on drill pipe and

drill collars. This helps make a pressure tight seal, and also allows easy

un-threading if there are problems. And the casing needs to be pulled back. On the

threading if there are problems. And the casing needs to be pulled back. On the

other hand, the threads on the guide shoe and float collar are doped with a

highly adhesive thread-lock compound, to prevent them from being spun and

un-threaded by the turning drill bit, during drill-out. If you can get hold of a

little left-over of this thread compound, it makes the very best, most permanent

glue you ever used!

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Cement Plugs

After the casing string is in place, the cement is introduced into the top of the casing string using a cementing head. Mixing with drilling fluid may degrade the setting ability of the cement, and so they are separated from teach other by the cementing plugs. Two different cementing plugs are used:

✔ Before cementing, the first, or bottom plug is put into the casing string. It has has a hollow core made of wood or some other easily drillable material (usually wood, or pot metal, an aluminum alloy) with an outer layer, at top diaphragm, and fins made of rubber. ✔ The bottom plug is followed by the calculated volume of cement slurry -- enough to fill all of the annular space between the casing

string and the open hole (with an appropriate safety factor for hole enlargement and fluid loss). The cement, which is normally heavier than the displaced drilling fluid, pushes the plug downwards, and the fins on the plug wipe the inside of the casing clean of drilling fluid, to prevent it contaminating the cement.

✔ When the calculated volume of cement has been added, the second or top plug is placed into the top of the casing string. This plug is identical to the bottom plug except that it has a solid core of wood or other easily drillable material.

✔ The top plug is followed by pumping the calculated volume of drilling fluid -- enough to drive the cement out into the annular space between the casing string and the open hole, leaving little or no cement remaining inside the casing string.

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

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✔ When the bottom plug reaches the float collar, it is stopped (or it bumps), the cement displacement is temporarily halted, and a back-pressure is noted at surface to mark the event.

✔ Because the bottom plug is hollow, only the thin rubber diaphragm preventing further displacement does not long survive the increased pressure. Almost immediately, the diaphragm bursts, cement flows through, and continues to be displaced below the float collar and out into the annulus.

✔ When the top plug reaches the float collar, it also bumps, and cement displacement is once again halted, and a second back-pressure is noted at surface to mark this event.

✔ Because the bottom plug is solid, no further displacement is possible and pumping must stop. The calculated volume of cement now remains below the float collar and in the annulus.

✔ Although the cement in the annulus is usually denser than the drilling fluid, it could flow back into the casing string, but the float

collar acts as a one-way valve, and prevents it from flowing back.

✔ The casing is lowered slightly, enough to latch it into the casing hanger, and the casing string is pressure sealed.

After the cement has set, and the casing string and blowout preventers have been pressure tested, then it is possible to trip a smaller drill bit into the hole, drill out the drillable materials of which the float collar, guide shoe, top and bottom plugs are made, and the small volume of cement retained between the float collar and the guide shoe, and then begin drilling new formation.

Oil Well Cement

The cement used in bore-hole applications, is basically Portland cement with some additives, and enhancers, similar to those used in drilling fluids. For example:

✔ Accelerators to promote the setting of cement, and reduce excessive waiting time, particularly in cooler, shallower environments. ✔ Retarders to extend the time over which the cement slurry remains pump-able. At higher down-hole temperatures, the chemical

reaction between cement and water is accelerated, and thickening time reduced. ✔ .Lightweight additives to reduce slurry density, or

✔ Heavyweight additives to increase cement slurry density when abnormally high formation pressures are expected ✔ Fluid-loss additives to reduce filtration rates and fluid loss, similar to that of drilling muds

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Unlike drilling fluid, it is preferred that cement displacement be in turbulent flow to promote more efficient flushing of mud and filter cake from the annulus.

✔ Lost-Circulation Additives to prevent extreme fluid loss.

In most circumstances, lost circulation additives are used with the conditioning drilling mud, so that the thief zone can be thoroughly sealed before casing and cementing is attempted. In worse situations, however, it may be necessary to add fibrous, and granular lost circulation materials to the

cement itself.

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

Bore-hole Volume & Displacement

To the mud logger, the most important drill string information involves the numbers, lengths, inside and outside diameters of the drill pipe and drill collars used in the

assembly. This is called the pipe

tally. The count of pipe joints and

the measurement of their lengths are made by the driller and his crew, but the mud logger must keep an independent pipe tally. In practice we find that calculation errors are far more common than

measurement errors. Working independently with regular cross-checks, the driller and mud logger can find and correct errors before serious

In yet other situations, extreme lost circulation while drilling may be treated by pumping a slug of cement

slurry mixed with lost circulation materials into the thief zone. Another trick is to pump a slurry of dry

Portland cement mixed with diesel or crude oil. The cement will, of course, not set while it is mixed with

oil. However, when the slurry is lost into the thief zone and mixes with formation waters, it will rapidly

set, and seal the zone. Lost circulation is discussed in more detail

later

.

It takes a little diplomacy, of course. If you start by out by

telling

the driller he's wrong then, more than

likely, you'll end by changing your depth calculation to match his -- only to have to change it back again,

when a more trustworthy wire-line log, or drill string re-measurement (aka

strapping out of the hole

)

becomes available. Better to ask if you can see his tally book, in order to find out where you may have

gone wrong.

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problems develop.

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

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Figure 19 shows an example bore-hole profile. In everyday calculations it is acceptable to make certain simplifications:

✔ The drill bit, stabilizers and other subs are ignored so that the inside and outside diameters of the drill collars are used for the entire bottom hole assembly,

✔ We ignore internal and external upsets, so that drill pipe is assumed to have uniform inside and outside diameters.

Both of these assumptions are acceptable within the limits of error in other input data. For example, the estimated diameter of the un-cased, open bore hole.

From the measured output of the mud pumps and the known dimensions of the drill bit, drill pipe and drill dollars, you can compute the drill string displacement, annular volume and the downward and upward circulation times.

For each section of the bore hole:

... Equation 1

... Equation 2

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... Equation 4

For the entire well:

... Equation 5

... Equation 6

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Where:

C_A = Annular capacity, cubic meters C_B = Boreholes capacity, cubic meters C_S = Drill string capacity, cubic meters DS = Drill string displacement, cubic meters DnA = Bore hole inside diameter, millimeters DnB = Drill string outside diameter, millimeters DnC = Drill string inside diameter, millimeters Ln = Annular section length, meters

QP = Mud pump output, cubic meters per second TC = Drilling fluid circulation time, seconds TD = Drilling fluid down time, seconds TL = Drilling fluid up or lag, seconds

Although these calculations are quite simple, most people like to have a little help with this kind of problem. Figure 20 provides the

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Drilling Fluids

Once the drill cutting have been released by drilling, they must be carried from under the face of the drill bit into the outer annulus and then back to surface. This is the job of the drilling fluid. Drilling fluids may be liquid or gas-based. There are differences in the circulation

equipment needed for each of these fluid types and, for each, there are definite advantages and disadvantages in drilling operations and sample recovery quality.

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

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A column of dense, water or oil-based drilling fluid applies a hydrostatic pressure on the bottom of the hole to overbalance formation pore pressure and prevent uncontrolled fluid influx: a well kick or blowout. Unfortunately, excessively dense fluid applies too great an

overbalance and holds the drill cuttings and other broken material in place beneath the drill bit. Several rotations and many tooth impacts are required before the cuttings are small and loose enough to be carried away from below the bit by the fluid jetting from the bit’s jet nozzles. If mud density is excessive, this chip hold-down effect will produce very small, excessively ground cuttings and, by preventing access to fresh, uncut formation, will retard rate of penetration (Figure 21).

If the differential pressure is lower or negative (meaning that the formation pressure is greater than bore-hole hydrostatic pressure), then formation fractures caused by the bit will be enlarged and extended by flowing, expanding pore fluid. Large, fresh-surfaced cuttings will be carried quickly away from bottom, exposing fresh formation to the bit for increased rate of penetration.

Gas-based drilling fluids offer an extreme occurrence of this. They have extremely low density and so provide almost no hydrostatic

pressure at the bottom of the hole. Cuttings are blown explosively from under the drill bit and carried back to surface at very high velocities. The maximizes rate of penetration, but the violent removal of cuttings results in their almost total disintegration. Gas drilled cuttings often consist of fine rock flour of little use to the geologist.

Liquid-based fluids travel to surface with their load of cuttings at a much lower pace, allowing efficient, safe recovery of whole cuttings. Cuttings recovery or lag time is controlled by the mud flow rate, annular capacity and well depth. It will also be modified by the mud flow regime, cuttings shape, size and density (Figure 22).

In laminar and turbulent flow, there is a velocity distribution in the annulus with mud flowing faster in the center of the annulus and slowest at it’s inner (drill pipe) and outer (bore-hole wall) boundaries. Solid particles tend to slip outward from the high velocity central region to the low velocity margins.

Slippage rates vary with particle shape, size and mass resulting in a non- uniform, partial mixing of cuttings with material from the formations above and below.

A geological sample log created from the examination of cuttings samples will never show truly sharp formation boundaries. Despite sharp drilling rate changes, drilling breaks, the cuttings are always mixed and honest cuttings descriptions will appear to indicate apparently transitional bed boundaries. This

must be considered when combining drilling measurements, cuttings observations and other mud logging data to prepare an interpreted presentation of the formations penetrated.

This is an important reason why the recommended mud log format used in this book includes two

cutting lithology columns:

One for accurate presentation of actual cutting components and amounts,

The other for an interpretation of the actual formations penetrated and their boundaries

based on all available real time observations and measurements.

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

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Water-based Mud

The most common drilling fluids are so-called gel muds

consisting of mixtures of water and a pure high-yield clay. They have an excellent carrying capacity for drill cuttings at

reasonable annular velocities and, when fluid flow is halted, the fluid rapidly forms a stable colloidal gel to prevent the cuttings from settling.

The clay-water slurry provides adequate density to control most subsurface pressures, and they filter out of the mud into permeable formation, to line the bore-hole wall with a smooth impermeable filter cake.

The common components of a water-based mud can be divided into four functional groups:

Water

✔ Fresh,

✔ Brackish water, or

✔ Marine brines (seawater) are used

Commonly, whatever water is available at the well site is used.

Clay

✔ Wyoming Bentonite is used for fresh and brackish

water systems but it does not yield (swell by absorbing water) easily in more saline water.

✔ Attapulgite or Salt Gel does not have so great a

maximum yield but is more responsive in sea water and brine systems. Pre-hydrated, and chemically stabilized, Bentonite may also be used with seawater-based muds.

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

Rotary Drilling

The On-line

The On-line

Mud Logging

Mud Logging

Handbook

Handbook

by Alun Whittaker

by Alun Whittaker

Rotary Drilling

Rotary Drilling

Aegis Group

244 Ohio Street

Vallejo, CA 94590-5051

USA

Rotary Drilling

Table of Contents

Chapter Summaries

Index

List of Figures & Tables

Rotary Drilling

Makin' Hole

The Drilling Rig

Hoisting Components

First time at the well site? Then one of the first things you will learn is

First time at the well site? Then one of the first things you will learn is

that the tall

that the tall

tower

tower

that dominates every view of the rig is rarely referred

that dominates every view of the rig is rarely referred

to as the tower. Usually, it is called the

to as the tower. Usually, it is called the

derrick

derrick

or the

or the

m ast

m ast

.

.

Then, you will learn that the 8 or 12-hour work shift on the rig is

Then, you will learn that the 8 or 12-hour work shift on the rig is

commonly referred to as a

commonly referred to as a

tour

tour

, but that word is pronounced like

, but that word is pronounced like

tower

tower

. So if you're told to be there for (what sounds like) the

. So if you're told to be there for (what sounds like) the

graveyard

graveyard

tower

tower

, plan on arriving at midnight for the late night--early morning

, plan on arriving at midnight for the late night--early morning

work shift.

The Deadline Anchor

Blocks

Draw Works

Rotating Components

Rotary Table

Top Drive

Down-hole Motor

Circulating Components

Regrettably, I am neither a veterinarian, nor a Texan, and so I am

Regrettably, I am neither a veterinarian, nor a Texan, and so I am

unable to add any elucidation regarding either the origin, or the

unable to add any elucidation regarding either the origin, or the

aptness of these names.

The Drill String

Drill Pipe

Drill Collars

Stabilizers

Drill Bit

When a junk sub is run, the mud logger should always be on hand