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DDDrrr iii lll lll iiinnnggg ttthhheee wwweeelll lll From pits to cable Oil seeps, shallow pits, mine shafts, strip mines spring poles and cable tool drilling rigs have all been used at some point in time, when exploring for oil in the historical past (Figure 131a and b). Each new technology was supplanted by the next, although by the late 19th century the cable-tool drilling rig represented the state of the art. Developed in Europe for the drilling of water wells, it was readily adapted for petroleum exploration by North America drillers (Brantly, 1971). Both the spring pole and the cable-tool drilling rig were essentially percussive techniques, with the motive power provided by either muscle (human or animal) or an engine (e.g., steam). The rate of progress was slow, measurable in meters per day, not meters per minute! Limited by their technology, drillers could not drill very deep wells. Because cable-tool drilling was also an 'open hole' technique the ability to combat a 'kick' was very limited, hence, the common occurrence of 'gushers'. Drillers needed a better drilling technology (Figure 131b).

Rotary drilling Introduction Rotary drilling (Figure 132) superseded cable-tool drilling because it was possible to drill wells with greater rates of penetration, and with an enhanced degree of safety. Some aspects of rotary drilling have not changed since the early 1900’s. However, many notable developments occurred during the middle of the twentieth century that enabled deeper wells to be drilled in areas unthinkable in 1900. Such as, the development of the tri-cone bit, non-rotating polycrystalline diamond bits, electric drawworks, the development of down-hole motors, the development of hydraulic blow-out-preventers, the development of polymer drilling fluids, the development of the riser and the initial invention and subsequent refinement of petrophysical-logging tools. More recently, the industry has seen the development of flexible drillpipe, top-drive motive units, the widespread application of horizontal drilling, the widespread use of mud telemetry and measurement whilst drilling (MWD) tools, the ubiquitous use of computers and the remote monitoring of operations.

Figure 132. Conventional on-shore rig schematic (courtesy of California Department of Conservation).

Figure 131. A Fifteenth century Chinese drilling tool (a), and Patent drawings for an early “Ross” drilling rig and equipment of 1891 (b) (Brantly, 1971; with permission of Gulf Publishing Co.).

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Figure 133. Nabors #9 on location in western Canada.

Drilling Terminology and Equipment

Land Rigs There are numerous types of land-rig, ranging in size from the large 'conventional' triple, through light weight helli-rigs, to the small portable coiled-tubing rig. Variations in size reflect differences in function and the load-bearing limit of the drawworks, derrick and traveling block (Figure 132). Large land rigs must be broken down into transportable units. Where roads or bridges pose weight limits, the helli-rig can be flown into a remote location piece-by-piece and assembled at the drillsite. Full size conventional rigs are typically large triples (Figure 133), equipped with substantial masts that are capable of handling the heavy drill-strings required when drilling a deep (vertical) well, unlike the lightweight mobile rigs designed for horizontal wells (small doubles, mobile rig), which typically can not handle heavy strings of drill pipe.

Off-shore rigs Barges: These are essentially ‘land rigs’ built upon a shallow hull designed for water depths of 3 to 7 m. The rig is towed to the drillsite and the hull is flooded so that the broad bottom of the barge sits on the seabed or lakebed. Islands: Seasonal ice and a very short drilling season typify the Arctic. The solution is to build an island upon which a winterized land rig can be placed. The island permits year-round drilling on the continental shelf, instead of being limited to ice-free months during the summer. The island prevents ice from crushing the rig, which is a hazard for floating rigs. Jack-ups: This type of offshore rig is designed to work in shallow water within the confines of the continental shelf and in water depths of approximately 50 to 80 m. This type of rig has a hull and three or more legs that provide support for the rig. The jack-up rig is towed or carried to the drill site by boat with the legs fully raised. Once at the drilling location, the support legs are lowered and the rig platform ‘jacked-up’ so the legs are in contact with the seabed and the platform clear of maximum peak wave height (Figure 134). The derrick is typically ‘skidded’ over the rear during drilling. Because the jackup rig is fixed to the seabed, the hull of the rig and drill floor do not experience vertical motion due to tides or wave action. Therefore, the ‘riser’ is fixed and a motion-compensation system is not required on this type of rig. Some jack-up rigs are often equipped with blowout preventers under the drill floor. Semi-submersibles: This is a floating type of drilling rig, designed for medium and deep water (Figures 135 and 136). The semi-submersible rig, known as a ‘semi-sub’, has either large pads or pontoons at the base of each leg which provide buoyancy while traveling to the drill site, but are subsequently partially flooded during drilling to give the rig the required drilling draft. The pontoons are ideally below wavebase to reduce the motion of the rig, but they also add a degree of stability when handling large amounts of drill pipe during drilling by lowering the semi-subs center of gravity. At the drill site, semi-subs are either anchored in place or use dynamic positioning, comprised of thrusters fore and aft that help maintain the rigs position over the wellhead. Because semi-subs are floating rigs, they are subject to the influence of tides and wave motion. They are therefore equipped with a ‘motion compensating system’ which is attached to the ‘riser’ and the drillstring traveling system. The riser (Figure 137a and b) is a large diameter telescopic tube that connects the drill floor to the borehole via the blowout preventers.

Figure 134. A jack-up rig.

Figure 135. A modern dynamically positioned twin-hulled semi-submersible rig.

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Figure 136. A semi-submersible rig in Galveston.

The riser is an extension of the borehole through the water column, that enables the return of drilling fluid within the annulus from the borehole to the rig. The lower part of the riser (Figure 137a [#2] and Figure 137b [#4]) is attached to the blowout preventers on the seabed, which in turn is attached to the casing that lines and protects the borehole. The upper sleeve (Figure 137b [#5]) is attached to the floating rig. As the rig moves vertically, in response to tidal and wave motion, the upper sleeve moves up and down inside the lower sleeve through the slip joint. Note that steel cables (Figure 136b) support both the upper and lower sleeves. The cables are a key element of the motion compensation system and are constantly tensioned (Figure 137c [#8]) by lengthening and shortening the wire suspension system in synchrony with the vertical rise and fall of the rig. The motion compensator system is also linked to the traveling block (Figure 137c [#9]) ensuring that the drillstring is also in synchrony with the vertical rise and fall of the rig.

The opening and closing of any ram within the blowout preventer system is controlled from the rig via hydraulic lines (Figure 136b [#7]). Think of the riser as a mechanical extension of the borehole, with the drillstring in the center of the riser/borehole and drill cuttings etc., returning up the annulus. Without the motion compensation system, it would be impossible to drill in deep water. The development of the motion compensating system ensures that the bit maintains constant torque and does not bounce up and down in the borehole as the rig moves up and down in response to tidal or wave motion. Both the riser and the blowout preventer system permit the safe exploration of very deep water plays, with depths of 3,200 m (10,011 ft) and storm wave height of 30 m within range of the largest and newest rigs. Drill ships: Designed for medium and deep water, these mobile, self contained and self-powered rigs are unmistakably ‘floaters’ (Video 13, Figures 138 and 139). Unlike the semi-sub, these rigs do not need anchors to maintain their position over the well head; using computer controlled dynamic positioning and thruster system these rigs can position themselves over the wellhead in the

Figure 137. Images showing various aspects of the motion compensating system on a semi-submersible drilling rig. (a) A scale model of a semi-sub showing (1) sea level (drilling draft), (2) the riser and (3) the location of the blowout preventers as a subsea stack; (b) a view of the riser showing (4) the lower sleeve of the riser that is physically attached to the blowout preventers (BOP), (5) the slip joint that permits vertical movement by the drilling rig due to tides and waves, (6) wire suspension system, (7) BOP hydraulic control line; (c) (8) pneumatic tensioners, (9) the traveling block system.

Video 13. Deepwater drillships. Courtesy of the American Petroleum Institute, copyright API 2007.

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deepest of water. The derrick is located centrally, over a ‘moon pool’, a purpose built opening through which the riser is run. Like the semi-submersible, drillships also utilize motion compensation apparatus, however, unlike 'semi-subs', drill ships often have the ability to store supplies, drill pipe, casing, etc., in the hull of the ship to lower the center of gravity and increase stability.

Platforms: These are fixed structures that are typically anchored to the sea floor via a steel or concrete support structure (Figure 140). The super-structure contains the drilling rig, living quarters, and production equipment and is purpose built to serve a given oil field for several decades. The production platform signifies an important part in the life cycle of an offshore oil field, because it moves the oilfield from the exploration and appraisal stage to the production phase. Offshore production is very rarely conducted through an exploration well. The optimal recovery of petroleum from a reservoir or several reservoirs off-shore requires the drilling of numerous wells, some of which are used to produce oil/gas, whereas others are used to enhance the recovery as injector wells, via water or miscible fluid flood. Because a platform services a number of wells (Figure 141), the derrick can be repositioned over a given wellhead on skid beams. Some of the largest offshore structures ever built are platforms. Structures built on steel legs are called 'platforms', if the structure utilizes a concrete support it is known as a 'caisson'.

Figure 141. Subsurface perspective view of the production wells drilled in the Piper field, North Sea, from a single production platform (Maher et. al., 1992).

Figure 140. The Piper field production platform (Maher et. al., 1992).

Figure 139. The derrick of the Discoverer II.

Figure 138. A dynamically positioned drill ship

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Drilling techniques, problems and solutions

Conventional drilling The Drill String The rotating system consists of the drill string, swivel, kelly, kelly-saver sub and the rotary table. The drill string is comprised of drill pipe, drill collars, subs/joints, stabilizers and drill bit. Rotary power is transferred from the rotary table, through the rotary bushing (Figure 142) to the kelly, which in turn is connected to the drill string. The drill string is divisible into 'drill pipe' and the 'bottom hole assembly' (BHA). In a conventional system the drill string transfers torque and rotary power to the bit, provides a conduit for the circulation of drilling fluid and provides both support and compressive weight to the drill bit via the BHA.

Drill pipe Drill pipe is not complicated. Drill pipe is made in 31 ft (9.4 m) lengths, known as a ‘single’ with a nominal tube outside diameter (OD) of either 4.5 or 5.0 ins. (114 or 127 mm) and tool joint tube OD diameter of either 6.25 or 6.5 ins. (159 or 165 mm), respectively (Smith International, 1992). The nominal inside diameter (ID) dimensions for the two types of pipe are 2.75 and 3 ins. (70 or 76 mm) respectively. Typical weight for a single length of drill pipe is 16.6 lbs ft (24.6 kg m). The drill pipe runs from the kelly saver sub, extending down into the borehole, to the top of the BHA. As the depth of the borehole increases more drill pipe is added.

The BHA The composition of the BHA (Figure 143) has great bearing on the drilling behavior and characteristics of a given drill string. Unlike drill pipe, the BHA can be complex. After the bit, perhaps the two most important components of the BHA are the drill collars and stabilizers. Drill collars are thick-walled, heavy lengths of pipe finished with either a smooth surface or helical ribs (Figure 144). The maximum permissible outside diameter of drill collar is determined by the cutting diameter of the drill bit. For example, 11 inch (279.4 mm) OD drill collar could be used in conjunction with a 12½ inch (311 mm) or larger bit, whereas smaller diameter drill collars would be used with a smaller bit. Engineers want to run the largest diameter drill collar possible because drill collar stiffness increases by the fourth power of the diameter (e.g., 9 inch drill collars are × 4 stiffer than 7 inch, but only × 2 stiffer than 8 inch drill collars). Another reason for selecting maximum diameter drill collar is weight. A 31 ft. (9.4 m) length of 11 inch (279.4 mm) drill collar weighs approximately 9,498 lbs (4286 kg), that’s about 306 lb per ft (Smith International, 1992). The BHA provides weight onto the bit and maintains tension within the drill (i.e., to avoid buckling). To control pipe flexure and buckling, the BHA typically contains stabilizers. Stabilizers are used to control drill angle, prevent dog-legs, key seats and

reduce the potential for 'differential sticking' (discussed below). There are three types of stabilizer; rotating blade, non-rotating sleeve and the roller cutter reamer. Stabilizers are designed to make contact with the wall of the hole. The type and number of stabilizer used will impact upon the geologists' work by adding caved material to the drill cuttings. Rotating blade stabilizers (Figure 145) have a 'spiral appearance', they turn with the drill string and will, therefore, dislodge geologic material from the wall of the borehole. Non-rotating stabilizers (Figure 143a) behave like a 'rudder' as the drill string rotates within the sleeve of the stabilizer. Stabilizers act as 'pressure points' and as a means of keeping the drill string in the center of the borehole. Figure 143 perhaps shows two extremes. The upper BHA (Figure 143a) is a packed BHA, because there is a high proportion of stabilizer [i.e., 1 and 3] relative to drill collars [2] or other components, such as jars, subs or shock-subs [4]. What the packed BHA achieves is a straighter borehole trajectory because pressure (i.e. weight-on-bit: WOB) is distributed evenly across the cutting-surface of the bit. This is not the case when stabilizers are omitted from the BHA (Figure 143b), where increased WOB causes the pipe to buckle producing an unequal distribution of pressure across the cutting-surface of the bit. This latter configuration can initiate a deviated borehole.

Figure 142. Rotary table and kelly bushing (Image copyright Schlumberger, Ltd. Used with permission).

Figure 143. BHA (Smith International, 1992; used with permission).

Figure 144. The rig floor of the Discover II during a trip.

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Making a 'connection' and 'trips' The entire drill string is supported by the traveling block and swivel (Figure 132). Rotary power is traditionally transferred from the kelly bushing to the drill string via the kelly, which has a hexagonal cross-sectional shape. The kelly can move freely up and down through the kelly bushing. As the depth increases the kelly passes through the kelly bushing. Once the kelly reaches it's lowest point, the kelly is raised through the kelly bushing, unscrewed from the drill string and a new length of drill pipe added. The kelly is then reattached, drilling re-continues until the kelly has been worked through the rotary bushing, the kelly is then once again unscrewed, new pipe added and so on. The business of adding new lengths of drill pipe is called 'making a connection' and is often a manual operation (Figure 146). Changing the drill bit requires the complete removal of the drill string in 27 m (90 ft) lengths, known as ‘stands’. Changing the bit is known as tripping the bit or simply tripping (Figures 144, 145 and 146). Short trips or wiper trips are periodically run to ensure the drill string does not get stuck. In this case the bit and BHA are not retrieved and broken down into 27 m lengths, but worked like a (slow) piston to condition the borehole.

Drill bits The role of the drill bit The drill bit does the work of cutting, chipping, grinding or gouging the formation and deepens the borehole. The actual cutting characteristics of a given bit are matched to the lithological characteristics (e.g., hardness, abrasiveness) of the formation to be drilled and specific drilling objectives. Tri-cone roller-bits (Figure 147) fitted with carbide insert teeth or milled-steel teeth are the most common varieties currently in use in land-based drilling operations. However, ‘unconventional’ bits that have non-moving parts (e.g., PDC, see below) are becoming increasingly common on deep or technical wells, especially off-shore. One reason is cost. The other is the relative cost of a given drill bit compared to the daily cost of drilling a well. When daily costs are high, the PDC drill bits with very high cutting efficiencies and longer wear rates are desirable irrespective of their cost.

Roller bits Modern roller bits are typically comprised of three rotating cones (Figure 147). The length of the teeth, the degree of ‘cone offset’, type of bearings and tooth construction (e.g., milled steel or tungsten carbide insert) govern the allowable weight and rotational speed limits of a drill bit. Specific types of drill bit are constructed to match specific types of formation, such as ultra soft (e.g., unconsolidated sands), medium (e.g., shale) to very hard (e.g. abrasive and well cemented sandstones). Soft formations are optimally drilled by 'gouging' the formation with long teeth, rather than chipping or fracturing as in the case of the short ‘button bit’, which is designed for highly indurated and abrasive formations. 'Gouging' is achieved by increasing the degree of cone 'offset'. The yellow lines in Figure 147b show that the apices of the three cones do not come to a single point in the center of the bit face, each apex is 'offset' from the true center. The greater the 'offset', the more the teeth twist and gouge the formation. Hard formation drill bits have no offset, whereas tri-cone bits, optimized for ultra soft formations, have the greatest offset! Geologists who regularly have to examine and describe drill cuttings (e.g., wellsite geologist) would be well advised to acquaint themselves with the characteristics of the specific drill bit used and BHA configuration because of the impact these tools have on drill cutting characteristics and the possible presence of caved material. Long tooth bits gouge, medium tooth bits cut, whereas short insert teeth chip and fracture the formation during drilling. In this way the shape and size of drill cuttings is largely determined by the type of bit used. Cavings are often derived from stabilizers or centralizers as drill collars or drill pipe contact the wall of the borehole.

Figure 145. The rig floor of the Discover II during a trip. Note the stabilizer.

Figure 146. Adding pipe.

Figure 147. The side view of a tri-cone roller bit (a); and the bit face (b), illustrating cone 'offset'; click on each image to activate the QuickTime VR (courtesy of OneEarth Virtuals),

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Figure 148. PDC bit (Image © Halliburton Company, used by permission).

Fixed cutter bits Fixed cutter bits (Figure 148) have no moving parts. The cutting surfaces, which are typically made out of polycrystalline diamond (PDC), are aligned as blades. Fixed cutter bits are designed to handle high RPM's (e.g., 160 rpm) and are specifically designed to work with down hole motors or top drive units. A downhole motor is typically a hydraulic motive unit that is part of the BHA behind the bit. Bit rotation is provided by the downhole motor and not via the rotary table-kelly-drillstring system. Topdrive units permit the use of longer lengths of drillstring, however, the drillstring does rotate.

Drilling fluid Function Drilling fluid, commonly referred to as 'mud', has several functions (Videos 14 to 16). It cools the bit, keeps the cutting face of the drill bit clear of cuttings, exerts hydraulic impact on the formation, provides a telemetry medium, prevents the ingress of formation fluids during drilling or tripping, lines the borehole with a ‘mudcake’ (Video 16) and last but not least it transports cuttings and formation gas to the surface for analysis. There are a variety of drilling fluids, includeing water-based, oil-based and non-fluid drilling fluids; the selection of which depends upon cost and the need to avoid engineering and/or geological problems.

Water-based systems This includes salt water-based and fresh water-calcium-based systems that typically incorporate bentonite or barite as the basic solid material. Fresh water weighs 1.000028 kg per liter or 8.3 lb per gallon, seawater has a weight of 1.02198 kg per liter or approximately 8.8 lb per gallon. Formation pressure increases with increasing depth, therefore, to counter the ingress of formation fluid the density (i.e., weight) of the drilling fluid must increase as depth increases. This is typically achieved by adding solids; either in the form of bentonite, barite or potassium-chloride (KCl) polymers. KCl fluid systems should not really be called ‘mud’ since they do not incorporate bentonite. The choice of freshwater or seawater is often decided by geography, the character of formation water and the general type of formation to be drilled.

Oil-based fluid systems Originally designed to prevent the dissolution of salts or anhydrite formations or the swelling of hydrophillic‡ shales (e.g., smectite) if present. From the geologist’s perspective oil-based fluid systems can be difficult to work with, but for the engineer, they prevent the differential sticking of the drillstring, reduce the tendency of hydroscopic shales to slough, possess a high degree of thermal stability and resist chemical contamination. But oil-based fluid systems require high maintenance, are expensive, have a high environmental cost and mask or prevent certain formation evaluation techniques from being utilized.

Non-fluid systems Some wells have been drilled using the circulation of compressed air or nitrogen foam to cool the bit and lift cuttings to the surface. This type of system is possible only on very shallow wells because non-fluid systems cannot counter the ingress of formation fluids.

Cleaning drilling fluid Fluid based systems are cleaned of drill cuttings using a de-sander, de-silter and 'shale shakers'. Shale shakers are large vibrating screens that remove drill cuttings from the drilling fluid. The 'mud' passes through the screens, the cuttings fall off the front edge of the screen and are collected for examination by the geologist.

‡ Hydrophyllic: a material (e.g., clay) whose surface has an attraction for water. Oleophillic: attraction for oil.

Video 15. Drilling fluid properties, from “The Making of Oil” (Copyright Schlumberger, Ltd. Used with permission).

Video 14. Drilling fluid, from “The Making of Oil” (Copyright Schlumberger, Ltd. Used with permission).

Video 16. Mudcake in the borehole, from “The Making of Oil” (Copyright Schlumberger, Ltd. Used with permission).

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Wellsite appraisal The Wellsite Geologist (Figure 149) is responsible for acquiring a complete and accurate evaluation of geological data, including the description of lithologies and the initial evaluation of ‘pay’ (i.e., oil or gas). The wellsite geologist should also keep other drilling personnel appraised with the necessary information to ensure a safe and efficient drilling operation. Depending upon the scale of the drilling program, the wellsite geologist may have additional responsibilities, for example, the monitoring and supervision of mud logging operations, monitoring and supervision of coring operation, the identification of core-point, core description, or the monitoring and supervision of the petrophysical logging operation.

Petrophysical logging Petrophysical logs are an important data source. They are used to evaluate the economic potential of a well, interpret lithologies, elucidate bedding and geological structure, correlate between wells and even help directional drillers track target lithologies. There is a successive chapter that deals with petrophysical logging in great detail. However, there are aspects to introduce at this point. The type of logging tools to be run (as a suite of tools) and the depths to be run is an integral part of the drilling prognosis. If a well is an exploration or an appraisal well the log suite to be run will typically be comprehensive and the logging budget may constitute approximately 5% (or more) of the total exploration budget. If the well is developmental, the number of logs to be run maybe reduced. Typically log suites are run prior to setting casing in the open hole section and can take typically one or two days to complete. The datum for all recorded data is the kelly bushing elevation. The elevation of the kelly bushing above sea floor is recorded on each log header. Corrections for true vertical depth and formation thickness are also given. Once drilling has ceased, the well is ‘conditioned’ by circulating drilling fluid for a number of hours, followed by removing the drill string from the well (trip). The logging sondes (Figure 150 'S') are lowered into the well suspended by an insulated cable attached to a winch unit (Figure 151). Once the logging depth is reached the sonde is turned on and spooled upward at 600m per hour. Depending upon the type of tool run, the signal may be transmitted via the cable or collected by a surface detector and recorded in the logging unit at the surface (Figures 150 to 152). There are some essential parameters that must be determined for a successful logging run. The first one is an accurate determination of mud filtrate and mud filter cake resistivity. The time since mud circulation ceased must also be recorded. If the drilling prognosis calls for an extensive suite of logs to be run, the on site engineer may wish to run the drill string back into the borehole, to recondition the borehole. The mud filtrate and mud cake resistivity should be checked for subtle changes that may affect final results. There is a wide array of logging sondes available, which are discussed in detail in a later chapter devoted to petrophysical logging.

Figure 149. The wellsite geologist .

Figure 150. Exterior rear view of a logging truck, with sonic sonde (S) (courtesy of OneEarth Virtuals, 2000).

Figure 151. The rear of a logging truck, showing the winch unit (courtesy of OneEarth Virtuals, 2000).

Figure 152. Logging truck interior, 'W' winch control, 'C' computer workstation, 'R' data and record unit (courtesy of OneEarth Virtuals, 2000).

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Deviations, dog-legs and key seats

Deviated borehole Wells are drilled to reach specific targets (i.e., a prospective reservoir), but must be drilled within the specified lease and according to an approved drilling prognosis. Therefore, the trajectory of the borehole must be controlled. Subsurface geology is rarely homogenous or arranged like flat-lying layers. Dipping strata, alternations of ‘soft’ and indurated lithologies and inclined fault planes can cause a borehole to deviate from a prognosed trajectory. There are also many instances when it is necessary to drill a controlled deviated borehole. ‘Designer’ wells are highly deviated wells that have a high degree of curvature and/or horizontal component to them. A ‘straight’ wellbore is one that is often regarded as having a total deviation of no more than 5o from vertical. However, as can be shown in Figure 153 problems can still arise due to the rate of change in borehole angle. Changes in borehole angle of 1 degree or more per 100m will generate a ‘dog-leg’; which is undesirable because it can lead to drilling problems, such as the creation of key seats and possibly stuck pipe.

Dog-leg and key seat A dog-leg is a sudden change in borehole angle, often caused by a change in lithology or structure, or due to changes in BHA configuration. If the drillstring is rotated by the rotary table, then the rotating pipe can initiate a notch where the drill pipe makes contact with the borehole, i.e., in the shoulder of the dog-leg (Figure 154). This notch is often the size of the drill pipe and is called a key seat. Wider diameter drill collars cannot be pulled through a key seat which can lead to stuck pipe and eventually pipe fatigue through jarring. Key seats are undesirable.

Whipstocks and controlling angle Borehole angle can be controlled or corrected, with some modicum of control, by careful configuration of the BHA. The strategic location of stabilizers combined with a judicious choice of WOB (weight-on-bit) and the effects of gravity, will allow the BHA to either build angle (via a fulcrum effect) or decrease angle (via a pendulum effect). When the stabilizer is located behind the bit and the WOB increased, the stabilizer acts as a fulcrum driving the bit into the side of the borehole. Conversely, if a stabilizer is positioned at some distance from the bit and the WOB is decreased, then gravity pulls the bit towards the vertical. Greater control of borehole angle can be achieved by using a steering tool or a whipstock. Devised in the 1930’s, this effective device (Figure 155, Video 17) remains one of the simplest ways of initiating a deviated borehole or creating a ‘kicking-off point’ for either ‘sidetracks’, re-entry wells, or initiating a horizontal borehole with a high degree of precision. The whipstock is run into the borehole to the desired depth and set in place. Once rotation of the milling assembly is begun the WOB is backed-off until the carbide blades of the mill contact the casing or borehole wall. A ‘window’ is then milled through the casing that initiates the ‘kick-off point (Video 17), followed by cleaning and reaming to ensure that subsequent BHA will not get stuck on the window. Well deviations drilled in the Prudhoe Bay of Alaska, using whipstocks, between 1991 and 1993 ranged from 2° to 67°, with an average of 35.2°.

Figure 154. The formation of a key seat (Copyright Schlumberger, Ltd. Used with permission).

Figure 153. Although this borehole is within the 5o target window, it has a total deviation of 6o and a dog-leg.

Figure 155. Some of the steps involved in ‘cutting a window’ and kicking-off a sidetrack well (Image copyright Schlumberger, Ltd. Used with permission). Video 17. The whipstock and ‘cutting a window’, from “The Making of Oil” (Copyright Schlumberger, Ltd. Used with permission).

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Casing

Overview Casing is large-diameter threaded pipe that is run into open hole and cemented into position to provide support and protection to the borehole. Casing isolates and protects sensitive, economic or potentially dangerous zones, such as fresh-water bearing formations, pay (i.e., reservoir) or formations with different pressure gradients. The lower most component of the casing string is the casing shoe, which is typically set within a formation of relatively low porosity and/or high tensile strength (i.e., high fracture pressure). Casing is always run from the BOP to the casing shoe depth. Successive, smaller diameter strings of casing are run inside previous (wider) casing strings, ensuring that the formations most susceptible to damage (i.e., upper part of the well) are protected (Figure 156).

Why run casing? At the most simplest level, casing provides added protection against the sudden and uncontrolled ingress of formation fluids into the wellbore. Casing protects the borehole from damage (‘invasion’), caving and uncontrolled fracturing. Formation pressure increases with increasing depth. However, that increase is never linear because of the existence of pressure gradients; that is the marked increase in pressure across discontinuities such as seals, unconformities, faults and lithology breaks. Typically, an increase in formation pressure gradient (Figure 157) can be matched by the hydrostatic pressure of the drilling fluid within the wellbore. The hydraulic head of pressure thus created is the most effective blowout preventer during drilling. As you will recall, if the formation pressure, at any depth, becomes greater than the hydostatic pressure of the drilling fluid, formation fluid will flow into the wellbore (a kick). Figure 157 illustrates the need for casing. Increasing the mud weight density to combat problems at depth can cause additional problems higher up the borehole, such as fracturing the formation and lost circulation. Both are additional hazards and should be avoided if possible. Therefore, casing provides an effective permanent means of dealing with increases in formation pressure. Typically the engineer needs to know an estimate of formation tensile strength (i.e., formation fracture pressure), depths of expected unconformities or faults, the presence of unusual formations (e.g., overpressured or underpressured formations) and the depth of a suitable formation for the casing shoe.

Figure 157. A hypothetical pressure gradient for an offshore Gulf Coast wellillustrating the need for casing. The diagram shows a generalized pressure gradient (red line) and mud weight density (blue line), the formation tensile strength is also given as a generalized line. Note that the upper 2,000 m is drilled with no change in mud weight density. However, where the formation pressure gradient exceeds the mud weight density a kick may occur. If the mud weight density is increased to over 1.25 gm cc (10.6 lb gal) and the borehole was not previously cased, the tensile strength of the rock will be exceeded and fractures will form in weaker formations at relatively shallow depth, with the possible loss of drilling fluid to the formation. Note also the significant and sudden increase in formation pressure below depth ‘X’. If casing is not set close to and above this point, the high mud weight density required below this depth to prevent a kick, would most certainly cause problems higher in the borehole. Problems such as the loss of drilling fluid to a formation of lower tensile strength and/or the fracturing of a weaker formation.

Figure 156. Generalized casing arrangement for a producing well (Image copyright Schlumberger, Ltd. Used with permission).

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Directional drilling An overview Directional drilling and many re-entry wells have become an essential component in many exploration strategies in areas that require a cost-effective means of enhancing production, the drilling of multiple targets from a single rig/platform, drilling around obstacles or the revitalization of marginally to sub-economic fields (Videos 18 to 20). Horizontal and ‘extended reach’ wells perhaps represent the ultimate examples of deviated well drilling. Over the last ten years the lateral reach (known as horizontal displacement) of such wells has increased substantially. An ‘extended reach’ well drilled from the Wytch Farm development (England) attained a horizontal displacement of 10,114 m (33,182 ft), horizontal displacements of 8,060 m (26,446 ft) and 7,852 m (25,764 ft) have been achieved in the South China Sea and North Sea respectively (Allen et al., 1997). Other example extended reach wells, drilled from land, include those off the south coast of Argentina, the north coast of Germany and the east coast of Sakhalin Island, Russia.

Horizontal wells are typically drilled using a significantly different drilling procedure from that of the vertical (conventional) and require specialized equipment, such as a flexible drill string, a steering tool and some form of ‘real-time’ downhole monitoring device (e.g., measurements-whilst-drilling device or MWD). The majority of horizontal wells are ‘kicked-off’ from a ‘vertical’ well, often using a whipstock (discussed above) or from an existing leg of a deviated well as a ‘re-entry’ well (Video 19). Once the initial window is cut through the casing the drill string is typically completely reconfigured with a downhole motor, bent-sub, a MWD tool, flexible joint(s), flexible pipe (or coiled tubing) an orientation tool steering tool or directional tool (Figures 158 and 159).

Figure 158. Generalized BHA used in drilling deviated wells; (a) short radius, (b) medium radius, and (c) long radius (Image © Halliburton Company, used by permission).

Figure 159. Orientation (steering) tools and down hole motor. (a) Down hole motor (lower) and angle selection joint. The yellow line is a non-perpendicular rotational surface. Rotating one end of the tool along that plane and to the desired angles bends the tool.

Video 18. Extending the life of a reservoir, from “The Making of Oil” (Copyright Schlumberger, Ltd. Used with permission)

Video 19. Extending the reach and increasing production, from “The Making of Oil” (Copyright Schlumberger, Ltd. Used with permission)

Video 20. Directional and horizontal drilling. Courtesy of the American Petroleum Institute, copyright API 2007.

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Because highly deviated wells, of which horizontal wells are but an example, have complex trajectories it is necessary to know where the drill bit is. This is achieved using a measurements-whilst-drilling device (MWD). MWD tools can be configured in a number of ways, with available modules that can provide geological, engineering and direction information. A magnetometer unit enables the directional driller to determine the location of the unit within the subsurface; which is important information if several targets are to be intersected with the same well (i.e., drilling ‘designer wells’). The configuration of the drill string is determined by the desired build angle or radius of curvature (Figure 158). Generally wells can be drilled in a long, medium or short radius (Figure 158, Video 21). Long radius wells often involve build angles of 2 to 6° per 30 m (100’) with horizontal legs of 1,250 m+, or 2 to 4° per 30 m (100’) in the North Sea, with horizontal legs of 400 m+. Medium radius in the continental USA involve build angles of 16 to 23° per 30 m (100’) with horizontal legs of 160 m, or 11 to 14° per 30 m (100’) in the Middle East (offshore) with horizontal legs of 350 m. Short radius wells, for example, have build angles of 1 to 3° per 30 cm (1 foot) in the Middle East (on-shore) with horizontal legs of 160 m. Figure 160 shows, in plan view, the well courses for production wells of the Piper field, North Sea. Each well is drilled directionally from the platform, which supported two derricks (Maher, et al., 1992). A perspective view of this field and the wells is given in Figure 141.

Why run highly deviated and horizontal wells? There are a number of reasons for running ‘horizontal wells’ and re-entry wells, which includes: • Increased contact with the reservoir. • Linear drainage of the reservoir along the borehole. • Reduced pressure gradient at the well. • Reduced number of wells required to maximize drainage. • Penetration of natural fractures or permeability conduits. • More effective drainage of laterally continuous thin reservoirs. • Cost effectiveness. However, not all formations are good candidates for horizontal or reentry wells. Costs can increase rapidly, especially if there are potential technical and engineering problems that could lead to the loss of the well. However, it is in the area of off-shore production that the drilling of deviated wells has been perfected. The ability to tap into the reservoir from a single production platform enhances the viability of many fields and makes effective use of expensive centralized infrastructure.

References Allen, F., P. Toons, G. Conran and W. Lesso, 1997, Extended-reach drilling: breaking the 10-km barrier, Oilfield

Review, Schlumberger, Sugarland, Texas, p.p. 32-47 Brantly, J. E., 1971, History of oil well drilling, Gulf Publishing Co., Houston, Texas, 1525p. Department of Trade and Industry, 2005, Department of Trade and Industry well numbering system, Petroleum

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Dessler, J. F., 1992, Marine seismic data acquisition, in: Development Geology Reference Manual (Morton-Thompson, M and A.M. Woods, Eds.), AAPG Methods in Exploration Series, No. 10, American Association of Petroleum Geologists, Tulsa, p.p.361-363.

Figure 160. A plan view of the Piper Field well courses (Maher et. al., 1992).

Video 21. Short v Medium radius, drilling from “The Making of Oil” (Copyright Schlumberger, Ltd. Used with permission)

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Dickey, P. A., 1992, Pressure detection, in: Development Geology Reference Manual (Morton-Thompson, M and A.M. Woods, Eds.), AAPG Methods in Exploration Series, No. 10, American Association of Petroleum Geologists, Tulsa, p.p.79-82.

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Maher, C. E., H. R. H. Schmitt and S. C. H. Green, 1992, Piper Field-UK, in: Structural Traps VI, Treatise of petroleum geology, atlas of oil and gas fields, (Foster, N. H. and E. A. Beaumont, Eds.), AAPG Treatise of petroleum geology, American Association of Petroleum Geologists, Tulsa, p.p.85-111.

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Schlumberger, 1997, The Making of Oil, Schlumberger Wireline and Testing, Sugarland, Texas. Schlumberger, 2007, on-line glossary: http://www.glossary.oilfield.slb.com/default.cfm Selley, R. C., 1985, Elements of Petroleum Geology, W.H. Freeman and Company, New York, 449p. Smith International, (1992), Drilco drilling assembly handbook, Smith International, Houston, Texas, 159p. Tinkler, J. C., 1992, Part1. Land and Leasing, in: Development Geology Reference Manual (Morton-Thompson, M and

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Whitaker, A., 1985, Filed geologists’ training guide: an introduction to oilfield geology, mud-logging and formation evaluation, Englewood Cliffs NJ, Prentice Hall, 291p.