5.1 INTRODUCTION |
The first stage in the extraction of crude oil from an underground reservoir is to drill a well into the reservoir (Speight, 2014). Often many wells (multilateral wells) will be drilled into the same reservoir, to ensure that the extraction rate will be economically viable. Also, some wells (sec- ondary wells) may be used to pump water, steam, acids, or various gas mix- tures into the reservoir to raise or maintain the reservoir pressure, and so maintain an economic extraction rate. |
In addition to creating drilling rigs that can operate at great water depths, new drilling techniques have evolved, which increase productivity and lower unit costs. The evolution of directional and horizontal drilling to penetrate multiple diverse pay targets is a prime example of technological advancement applied in the offshore. The industry now has the ability to reduce costs by using fewer wells to penetrate producing reservoirs at their optimum loca- tions. Horizontal completions within the formation also extend the reach of each well through crude oil-bearing (and/or natural gas-bearing) forma- tions, thus increasing the flow rates compared with those from simple vertical completions.These advancements can be attributed to several developments. For example, the evolution of retrievable whipstocks allows the driller to exit the cased wells without losing potential production from the existing wellbores. Also, top drive systems allow the driller to keep the bit in the side- tracked hole, and mud motor enhancements permit drilling up to 60° per 100-ft-radius holes without articulated systems. In addition, pay zone steer- ing systems are capable of staying within pay zone boundaries. |
New innovations in drilling also include multilateral and multibranch wells. A multilateral well has more than one horizontal (or near horizontal) lateral drilled from a single site and connected to a single wellbore. A mul- tibranch well has more than one branch drilled from a single site and con- nected to a single wellbore. Although not as pervasive in the offshore locale as in the onshore locale because of the necessity of pressure-sealed systems, multilateral and multibranch wells are more important factors in current (and future) offshore development. |
Finally, planning for drilling or any offshore operation should include environmental considerations (Chapter 9). In fact, as with any project with the potential to harm the environment, plans must be developed and permits applied for and received before moving any equipment onto the work site. After the plans and permits are obtained, the pre-spud meeting, in addition to discussing well depth, casing points, and rig selection, should cover topics pertinent to the environmental management of the drilling and comple- tion operation. Each site will have particular factors that differ from factors encountered at other sites (site specificity) and compliance with the regula- tion for the site is a must-do. It is also advisable because of public interest in any project that can affect the environment, to engage in public forums and public disclosure of a project should be made as early as possible, even during the time that the project is in the project pending stage.Well-presented public disclosure statements released to the potentially affected community may not allay all fears but can help in giving the public an undertaking of what is to be done. In such case, the public may be able to offer viable alter- nates that assist the project developer. The element of public surprise must (which often is the initiator for many objections) be removed. |
5.2DRILLING |
Drilling is the most essential activity in oil and gas recovery. Once a prospect has been identified through the use of geological and exploration techniques (Chapter 2, Chapter 4), it is only through the actual penetration of the formation by the drill bit that the presence of recoverable crude oil and natural gas can be confirmed.The challenging conditions that confront the number of drilling rigs qualified for deep-water operations are limited. |
Five rigs capable of drilling in up to 2,500 ft of water were operating in 1995. By 1996, nine were in operation and additional rigs were being up- graded for operations in deep water. Because this set of equipment has ex- panded more slowly than the demand for drilling in deep water necessitate specialized equipment. |
Currently, the major use of offshore structures is for the exploration and production of oil and gas—mobile exploratory drilling rigs are used to drill wells to determine the presence or absence (dry hole) of crude oil and/or natural gas at the offshore site. If crude oil or natural gas is present in suffi- cient quantity to warrant development of the field, the well is plugged until a permanent production platform is in place. During drilling operations, supply vessels continuously support the drilling vessel that has sleeping quarters for the crew and galley facilities, standby boats for safety purposes, a heliport, and are organized in self-contained or tendered configurations. |
Drilling offshore wells requires a modified drilling procedure when compared with onshore drilling—offshore wells are drilled by lowering a drill string (consisting of a drill bit, drill collar, and drill pipe) through a conduit (riser) that extends from the drilling rig to the sea floor. The steel drill pipe sections are typically 30 ft in length and weigh approximately 600 lb—as the drilling progresses, additional drill pipe sections are connected at the surface as the well deepens. |
For readers unfamiliar with drill bits, the roller-cone drill bit usually has three cones with teeth and is designed to break the rock by indention and a gouging action. As the cones roll across the bottom, the teeth press against the formation with enough pressure to exceed the failure strength of the rock at which rock fracture occurs. The lower part of the bit’s body sup- ports the roller cones, usually three (but also one, two, or four can be used). Each cone has two or three rows of teeth, which can either be milled from the same block of metal as the bit (“non inserts” bit) or be fabricated from tungsten inserts that are harder and more durable than milled teeth. The external, intermediate, and internal rows of a cone each have a different number of teeth and each tooth is like a chisel, and has a maximum height (penetration depth) and a semi-angle (the angle made by its lateral surface with the bit axis.The wedge of a new tooth can either be sharp or flat and each cone is protected externally by the lobed body of the bit legs. The cones are supported by bearings, which are lubricated and sealed.The bear- ing axis of the cone forms the cone-journal angle with the horizontal level (or normal to the bit axis). The offset distance is the distance between the cone axis and the drill-bit center (typically measured in millimeters and the offset angle is the angle the cone axis would be rotated to make it to pass through the central bit axis. |
Natural diamond bits are constructed with diamonds embedded into a matrix and are used in conventional rotary, turbine, and coring operations. Diamond bits can provide improved drilling rates than roller bits in some formations and all the diamond bit suppliers provide comparison tables between roller bit and diamond bit performance to aid users in bit selec- tion based on economic evaluation. Some of the most important benefits of diamond bits are: (1) bit failure potential is reduced due to there being no moving parts, (2) less drilling effort is required for the shearing cutting action than for to the cracking and grinding action of the roller bit, (3) bit weight is reduced, therefore deviation control is improved, and (4) the low weight and lack of moving parts make them well suited for turbine drilling. |
At the sea floor, the riser passes through a system of safety valves (blow- out preventer (BOP)), which is used to contain pressures in the well and to prevent a blowout leading to oil leakage. The BOP—similar to the system used in onshore drilling—prevents any oil or gas from seeping out into the water. In the old days of surface drilling, the blowout would be called the gusher, which was an environmental disaster. Above the BOP, a marine riser extends from the sea floor to the drilling platform above—the marine riser is designed to house the drill bit and drill string and is sufficiently flexible to accommodate the movement of the drilling platform. Strategically placed slip and ball joints in the marine riser allow the subsea well to be unaffected by the pitching and rolling of the drilling platform. |
At the surface, a rotary table at the surface turns the drill string and the drill bit teeth penetrate the sea floor sediment and the various rock forma- tions that overly the reservoir while a drilling fluid (often referred to as drilling mud) is pumped into the drill pipe from a tank on the surface and the mud flows through perforations in the drill bit. The drilling mud col- lects the cuttings of rock produced by the drill bit and flows to the surface through the annulus between the well casing and the drill string below the sea bottom (mud line) and the riser and the drill string above the mud line.A strainer (filter) is used to remove the cuttings from the drilling mud, which is then recirculated through the mud tank and pumped to the drill string. Discharge of these fluids and cuttings into ocean waters are governed by environmental regulations and protocols (Chapter 10, Chapter 11). |
The weight of the mud exerts a pressure greater than the pressure in the rock formations, and, therefore, keeps the well under control. As the drill bit penetrates further into the rock formations, strings of steel pipe (casing) are run into the well and cemented into place in order to seal off the walls of the well and maintain the integrity of the well by preventing collapse of the walls. |
One of the most important pieces of equipment for offshore drilling is the subsea drilling template, which is used to connect the underwater well site to the drilling platform on the surface of the water. The template consists of an open steel box with multiple holes—the number of holes is dependent on the number of wells to be drilled—that is placed over the well site in an a precise exact position using satellite and GPS technology. The drilling template is secured (cemented) to the sea floor and automatic shutoff valves (BOPs) are attached to the template so that the well can be sealed off if there are problems on the platform or if the drilling rig has to be moved. Cables attach the template to floating platforms and are used to position the drill pipe accurately in the template and wellbore, while allow- ing for some vertical and horizontal movement of the platform. |
The first stages of drilling typically penetrate 1500–3000 ft below the sea floor, after which steel casing is cemented into the hole—the casing helps prevent crude oil or natural gas from escaping into the environment. One of the primary differences between onshore drilling and offshore drill- ing is that, in offshore drilling, a large pipe (a riser) is used to connect the drilling rig to the seabed. However, the riser is not in place during the drilling of the shallowest part of the hole, but is installed after the casing has been cemented in place.The riser acts as a conduit for the drilling mud and drill cuttings which must be circulated through the well bore and back to the drilling rig so that the cuttings can be removed for disposal. |
The drill bit may be a mile or more below the sea bed before crude oil and natural gas resources are reached and the pressure between the reservoir and the well must be controlled by adjusting the flow and weight of the drilling mud. The mud must be sufficiently viscous (heavy) to keep reser- voir fluids from entering the borehole during drilling, but not so viscous that the mud penetrates the rock and prevents crude oil and natural gas from reaching the well.The first sign of success is usually an increase in the rate the drill bit penetrates the rock, which is often followed by traces of crude oil or natural gas in the rock cuttings brought up by the drill bit.This stage of drilling must be carefully monitored to prevent releases of crude oil and/or natural gas that might affect the environment. |
In some cases, instruments are sent down a wireline and into the well to determine the existence of oil or gas—if crude oil and/or natural gas are present, steel production casing is set in place and is used as the conduit for transporting crude oil and natural gas safely to the surface. The well fluids are typically a mixture of crude oil, natural gas, sand, and brine and the flu- ids are processed before being sent ashore through a pipeline or transported to shore by a tanker.The degree of processing of the well fluids is dependent upon pipeline requirements (which may limit the amount of sand and brine in the fluids) or tanker regulations. |
The wireline logging tools gather data about the thickness of rock lay- ers, porosity, permeability and the composition of the fluids (oil, natural gas, or water) contained in them. These tools can be mounted on the drill string above the bit to send information to the surface continuously dur- ing drilling, or they can be lowered into a well after it is drilled. Another instrument—a measurement-while-drilling (MWD) tool—is also used to measure the direction and precise location of the bit while drilling horizon- tal wells. A common way to determine potential oil or natural gas produc- tion is the drill-stem test in which a special tool replaces the bit on the end of the drill string and is lowered into the well. It allows liquids or natural gas from the formation to flow into the empty drill pipe.This gives a good indication of the type and volume of the fluids in the formation, their pres- sure and rate of flow. Regulations require that the sea floor at any well site must be left in the same condition after drilling as before. This means that the drilling crew plugs the well bore with cement and removes the subsea equipment. A similar procedure is followed when a producing well is no longer economical to operate. |
Offshore drilling for oil and natural gas offshore, in some instances hun- dreds of miles away from the nearest landmass, introduces many challenges to the challenge of onshore drilling. While the actual drilling mechanism used to drill into the sea floor is much the same as can be found on an on- shore rig, the sea floor can sometimes be thousands of feet below sea level. Therefore, while with onshore drilling the ground provides a platform from which to drill, at sea an artificial drilling platform must be constructed and used. In fact, drilling in deep and ultra-deep water is one of the main goals for the development of oil fields in new exploration areas. |
Underbalanced drilling (UBD), or near balanced drilling with light- weight drilling fluids, has practical applications offshore (Pratt, 2002; Bour- geois, 2003; Santos et al., 2003, 2006). UBD is a technique in which the hydrostatic head of drilling fluid is intentionally designed to be lower than the formation pressure. The hydrostatic head of the fluid may naturally be less than the formation pressure, or it can be induced by adding different substances to the liquid phase of the drilling fluid, such as: (1) natural gas, (2) nitrogen, (3) air.Whether the underbalanced status is induced or natural, the result may be an influx of formation fluids that must be circulated from the well, and controlled at surface.The technique is useful for infill drilling in depleted fields and in developing lower-permeability reservoirs. UBD is most often used to prevent formation damage since the lightweight drilling fluids are less likely to invade formations, and there is no filter cake or mud cake buildup to impede flow from the reservoir. |
There are four main techniques to achieve underbalance, including (1) use of lightweight drilling fluids, (2) gas injection down the drill pipe, (3) gas injection through a parasite string, and (4) foam injection. Using light- weight drilling fluids, such as fresh water, diesel and lease crude, is the sim- plest way to reduce wellbore pressure. A negative for this approach is that in most reservoirs the pressure in the wellbore cannot be reduced enough to achieve underbalance. The method of injecting gas down the drill pipe involves adding air or nitrogen to the drilling fluid that is pumped directly down the drill pipe. In the offshore environment where drilling challenges are presented, there is a narrow window between the formation pore pres- sure and fracture gradient (PPFG), which dictates conservative casing pro- grams during conventional drilling.There is also the challenge of flow haz- ards in shallow water where (1) rig space is limited, (2) the equipment must be small/compact, and (3) drilling gases and other drilling fluid components must be generated or stored on the rig. |
In order to drill underbalanced safely in the marine environment, there are different types of rotating control heads for rigs with either surface or subsea BOPs. Returns at the surface need to be controlled by a choke man- ifold system independent of the rig manifold. Drillers need tools to control and manage equivalent circulating density to prevent downtime. Floating vessels with risers require additional considerations that are not factors in land drilling.The riser is the weakest mechanical component in the blowout prevented stack, and the riser stress must be continually monitored. |
Advantages to this technique include improved penetration, decreased amount of gas required, and that the wellbore does not have to be designed specifically for UBD. On the other hand, disadvantages include the risk of overbalance conditions during shut-in. Additionally, there are temperature limits to using foam in UBD, limiting use of the technique to wells measur- ing less than 12,000 ft deep. |
Finally, dual-gradient drilling technology (dual density drilling technology) is being considered for ultra deepwater wells where the PPFG is particularly narrow and the need to reduce riser stress becomes critical. In this situation, two fluid gradients are maintained in the wellbore using seafloor pumps: (1) seawater in the annulus from the rig floor to the mudline, and (2) a mud column from the mudline to the topside. Mud returns to the surface via an auxiliary line, separate from the conventional riser. Another method of maintaining a dual density column, without a seafloor pump, is to use mud pumps to inject hollow glass spheres into the bottom of the riser to reduce the mud density in the riser to that of seawater. |
5.2.1Drilling Ships and Drilling rigs |
The drilling unit (drilling platform) can take many forms (Chapter 2), de- pending on the characteristics of the well to be drilled, including the under- water depth of the drilling target. Furthermore, in order to drill successfully the drillship (Chapter 2) must hold a constant position directly above the borehole in the ocean floor. And it must be able to do this in waves, wind, and ocean currents. Because of the great depths, anchors are out of the question and the ship retains its position by means of dynamic positioning, which is accomplished by computer controlled thrusters, some of which are mounted on hydraulic pods that retract into the ship when it is underway. |
The drilling ship uses satellite navigation systems to find the chosen drill site. When it is in position, transponders are dropped to the seafloor and the thrusters are extended beneath the ship.With the thrusters lowered, the bottom of the ship literally bristles with propellers. Computers on the ship use the transponder signals to activate the various thrusters, which can move the ship forward, backward, or sideways.The ship should also be able to drill relatively unperturbed in high seas. Instead of being connected directly to the drill rig, the pipe string is suspended from a heave compensator, which functions like a shock absorber. If the ship rises on a wave, the heave com- pensator lowers the drill string. More modern drilling ships may also con- tain laboratories such as those for core handling, sampling, physical proper- ties, chemical properties, thin section preparation, and X-ray photography. |
Drilling rigs that use such new technology as top-drive drilling and proposed dual derricks are reducing drilling and completion times. In light of the limited number of vessels available for drilling deep-water wells and the resulting increasing drilling rates for such equipment, shorter operating times are a key advantage expected from dual rig derricks. |
In addition to creating drilling rigs that can operate at great water depths, new drilling techniques have evolved, which increase productivity and lower unit costs. The evolution of directional and horizontal drilling to penetrate multiple diverse pay targets is a prime example of technological advancement applied in the offshore. The industry now has the ability to reduce costs by using fewer wells to penetrate producing reservoirs at their optimum loca- tions. Horizontal completions within the formation also extend the reach of each well through crude oil-bearing (and/or natural gas-bearing) forma- tions, thus increasing the flow rates compared with those from simple vertical completions.These advancements can be attributed to several developments. For example, the evolution of retrievable whipstocks allows the driller to exit the cased wells without losing potential production from the existing wellbores. Also, top drive systems allow the driller to keep the bit in the side- tracked hole, and mud motor enhancements permit drilling up to 60° per 100-ft-radius holes without articulated systems. In addition, pay zone steer- ing systems are capable of staying within pay zone boundaries. |
New innovations in drilling also include multilateral and multibranch wells. A multilateral well has more than one horizontal (or near horizontal) lateral drilled from a single site and connected to a single wellbore. A mul- tibranch well has more then one branch drilled from a single site and con- nected to a single wellbore. Although not as pervasive in the offshore as in the onshore because of the necessity of pressure-sealed systems, multilateral and multibranch wells are expected to be more important factors in future offshore development. |
5.2.2Top Drive Drilling |
Top drive drilling replaces the kelly method of rotation used in convention- al rotary drilling. Using hydraulic or electric motors suspended above the drill pipe enables top drives to rotate and pump continuously while drilling or during the removal of the drill pipe from the hole. |
Top drive drilling systems are one of the greatest contributions to the offshore drilling industry. Until 1982, the drill-string was handled and ro- tated by a kelly joint and a rotary table. Drilling and making connections on offshore rigs had been virtually unchanged for years.Then development of the top drive, which rotates the drill pipe directly and is guided down rails in the derrick, replaced the need for a kelly joint to rotate the drill string. It performs normal hoisting requirements such as tripping and running cas- ing. It also added the ability for drilling with triples, circulating and rotating during tripping, and back-reaming and/or freeing stuck pipe. |
Top drive drilling provides a safer drilling operation by reducing the haz- ards of rotary tongs and spinning chain. In addition, the pipe handling fea- tures use hydraulic arms to move drill pipe and drill collars to and from the V-door and monkey board, thereby reducing strenuous work and increasing pipe handling safety.The automatic, driller-operated pipe elevators eliminate accidents caused by drilling crews operating elevators manually during un- der balanced drilling operations. Well control capability is greatly enhanced because of the ability to screw into the string any point in the derrick to circulate drilling fluids.The remotely operated kelly valve reduces mud spill- age when back reaming or breaking off after circulating above the rig floor. |
The most important feature of the top drive is the ability to rotate and pump continuously while reaming into or out of the hole. Continuous ro- tation means substantially reduced friction when removing the string from or tripping back into directional or horizontal wells. In addition, there is less reservoir damage due to reduced usage and subsequent entry of gel/clay |
particles into the producing formation. |
However, the top drive system offers many other benefits, each of which act to increase the performance of the drilling rig and improve the return on investment for the well. For instance, top drives reduce the instances of stuck pipe. |
Historically, it has not been considered uncommon to get a drill string stuck in the hole from time to time, and the potential of stuck pipe in- creases with hole depth and the particular formation being drilled through. Regardless of the depth or type of the formation, drilling with a top drive drastically reduces the instances of stuck pipe. Drilling with 30 m of pipe at a time allows more time for hole conditioning and circulating solids to the surface. Also, because there are fewer connections to be made, the pumps are stopped less often.This results in less circulation time required to achieve uniform distribution of annular cuttings load. All of these factors help keep the bit and the string free to rotate and help prevent sticking. |
Besides the stuck pipe that could previously occur while drilling, drill strings can also encounter tight spots when tripping in or out of the hole. If a tight spot is encountered during a trip on a conventional rig, it becomes a major effort to pick up the kelly and begin circulating and rotating the pipe through the trouble zone. However, when tripping on a rig equipped with a top drive, rotation and circulation can be achieved at any point within a matter of seconds. The driller simply needs to set the slips, lower the top drive to engage the drive stem, make up the connection with the top drive pipe-handler, and begin circulation. This feature provides the driller with the added benefit of being able to back-ream whenever necessary. Entire sections of the well bore can be reamed through without significantly im- pacting trip times.The result is a conditioned and clean borehole, ensuring a successful casing run. |
The ability to quickly and easily connect to the drill string during trips provides benefits that extend beyond just preventing stuck pipe. For in- stance, consider the situation when a kick is encountered during a trip. On a kelly rig, the crew has little recourse and will find it very difficult to con- tain the fluids escaping the well without taking drastic measures. In the case where a top drive encounters the same situation, the slips can be set and the top drive connected immediately, thus containing and controlling the well within seconds of a kick being detected.These rapid responses to well kicks have increased the safety of the rig floor and have helped to protect drilling personnel from possible injury. |
Other aspects of top drive drilling have led to increased awareness of safety all around the rig floor.When kelly drilling, the rotary table and kelly bushing are spinning rapidly at the rig floor, while the crew is in close prox- imity. Since top drives eliminate the need for the kelly drive mechanism, and the rotary table is not used to rotate the pipe, the only thing rotating at the drill floor is smooth drill pipe. Also, since the top drive eliminates two out of three drilling connections, the drill crew is less exposed to possible injury; less exposure to possible injury results in less injuries. |
While improvements in drilling time and crew safety are well docu- mented, and these features can benefit any drilling rig, certain aspects of top drive drilling have allowed drastic improvements in oil and gas recovery from reservoirs. Enhanced recovery of crude oil and natural gas has been achieved through a combination of extended reach and horizontal drilling programs. Extended reach, or highly deviated wells, increases the horizontal area of a reservoir that can be tapped from a given location. Horizontal completions allow a major increase in the ultimate recovery from a given reservoir. Both of these offers tremendous financial incentive from the op- erator’s perspective, and both of these situations can only be achieve by utilizing a top drive drilling system. |
In the case where geological, geographic, or economic factors limit the placement of drilling locations, it may be beneficial to deviate the wells drilled from a given location in order to access certain areas of a reservoir. This is achieved by drilling at angles from 70° to 90° from vertical for extended measured depth. When drilling with a top drive, and taking into account other parameters such as drilling fluid composition, it is now con- sidered commonplace to extend the horizontal reach to several miles. |
In fact, the productivity of a conventional well is proportional to the permeability-thickness product. Low productivities result from low values of permeability or formation thickness (or both).This can be compensated for in horizontal wells where the length of the horizontal section is not im- posed by nature but chosen.The permeability-length product in horizontal wells plays a role similar to that of the permeability-thickness product of conventional wells. In addition, to increasing productivity, horizontal wells have been shown to increase productivity, to reduce coning tendencies, and to improve recovery by a variety of mechanisms (Sherrard et al., 1987; Wilkerson et al., 1988;Wilson and Willis, 1986). |
The long wellbores allow longer completed intervals and therefore in- creased production rates. In reservoirs overlying an aquifer or located under a gas cap, the increased standoff from the fluid contacts can improve the production rates without causing coning. Additionally, the longer wellbore length serves to reduce the drawdown for a given production rate and thus further reduces coning tendencies. Fractured reservoirs can also benefit from horizontal wells. Long wellbores are likely to intersect more fractures and hence improve both production rate and ultimate recovery. Furthermore, the application of horizontal wells early in a project may allow development with fewer wells because of the larger drainage area of each well. In some fields, the advantages of horizontal drilling may allow development where conventional techniques would be uneconomical. |
Most offshore rigs now use top drives—hydraulic or electric motors suspended above the drill string. In some situations, the bit can be turned by a mud motor, a down hole hydraulic drive that is inserted above the bit at the bottom of the drill string. It receives power from the flow of the drilling mud. This technique is often used to drill directional and horizontal wells, which are important to offshore operations. Directional drilling allows a number of wells to be drilled from one location. Horizontal wells can pen- etrate a long section of the rock formation, providing better contact with the reservoir.This reduces the time it takes to extract crude oil or natural gas from the reservoir and in some cases increases the total amount of product that can be recovered. As drilling technologies and methods have improved, the reach of wells into producing formations continues to increase. |
5.2.3Dual Derricks |
The dual derrick system is a relatively recent drilling structure used for deep water drilling operations. Efficiencies exist from allowing dual hook load operations that make this type of structure advantageous (Effenberger et al., 2013). |
Most modern drillships have some degree of dual-rig activity (i.e., they have two drilling derricks on one hull) and have the capability to run two riser and two BOP systems with one system drilling and the other complet- ing a well on a subsea template. With this drill-and-complete mode on a multiwell template, efficiency is claimed to increase significantly. For explo- ration wells, it is possible to run casing with one derrick set and drill with the other, thus reducing total time to complete the operation. Some systems have the capability to produce and store crude oil, thus eliminating the need to flare or burn the produced fluid during well testing. |
The dual-activity capability units are, in general, exploration units with the development capability for large-numbered multiwell subsea templates in very deep water. Generally for exploration wells, the greater the depth of water and the shorter the well is, the more commercially attractive the dual-activity units become compare to a standard spread-moored semisub- mersible unit. |
5.2.4Directional and horizontal Drilling |
New methods to drill for oil are continually being sought, including di- rectional or horizontal drilling techniques, to reach oil under ecologically sensitive areas, and using lasers to drill oil wells. Directional drilling is also used to reach formations and targets not directly below the penetration point or drilling from shore to locations under water (Speight, 2014). A controlled deviation may also be used from a selected depth in an existing hole to at- tain economy in drilling costs.Various types of tools are used in directional drilling along with instruments to help orient their position and measure the degree and direction of deviation; two such tools are the whipstock and the knuckle joint.The whipstock is a gradually tapered wedge with a chisel- shaped base that prevents rotation after it has been forced into the bottom of an open hole and used to assure that the bottom of the drill pipe that is ori- ented in the direction the well is intended to take. As the bit moves down, it is deflected by the taper about 5 from the alignment of the existing hole. |
Directional drilling and horizontal drilling is the practice of drilling nonvertical wells. Many prerequisites enabled this technology to become productive. Probably the first requirement was the realization that oil wells are not necessarily vertical and there were several lawsuits in the late 1920s alleging that wells drilled from a rig on one property had crossed the bound- |
ary and were penetrating a reservoir on an adjacent property. |
Prior experience with rotary drilling had established several principles for the configuration of drilling equipment down hole (bottom hole assem- bly) that would be prone to drilling a crooked hole in which initial acci- dental deviations from the vertical would be increased. Counter-experience had also given early directional drillers principles of bottom hole assembly design and drilling practice that would help bring a crooked hole nearer the vertical. |
Combined, these survey tools and bottom hole assembly designs made directional drilling possible, but it was perceived as arcane. The next major advance was in the 1970s, when downhole drilling motors (mud motors), driven by the hydraulic power of drilling mud circulated down the drill string, became common.These allowed the bit to be rotated on the bottom of the hole, while most of the drill pipe was held stationary. Including a piece of bent pipe between the stationary drill pipe and the top of the mo- tor allowed the direction of the wellbore to be changed without needing to pull all the drill pipe out and place another whipstock. Coupled with the development of MWD tools, directional drilling became easier. The most recent major advance in directional drilling has been the development of a range of rotary steerable tools that allow three dimensional control of the drill bit without stopping the drill string rotation—these tools have im- proved the process of drilling highly deviated wells. |
To achieve directional drilling, downhole instrumentation is required to deflect the direction of the bit from the drill-string axis. Usually, the direc- tional tool is a downhole motor, either provided with a bending housing (steerable motor) or used with a bending sub above the motor. Another di- rectional technique uses the whipstock, which is a nonsymmetric steel joint forcing the drilling direction. Sometimes this tool is removed after drilling has taken the desired direction. |
Directional wells increase the exposed section length through the reser- voir by drilling through the reservoir at an angle and allow drilling into the reservoir where vertical access is difficult or not possible—such as when the crude oil reservoir is under a town, under a lake, or lies beneath a difficult- to-drill-formation. Directional drilling also allows more wellheads to be grouped together on one surface location and may not require as many movement of the drillship—there is also less surface area disturbance. For example, on an offshore oil platform, up to about 40 wells can be grouped together—the wells fan out from the platform into the reservoir below. Furthermore, directional drilling allows drilling relief wells to relieve the pressure of a well producing without restraint (blowout) in which another well could be drilled starting at a safe distance away from the blow out, but intersecting the troubled wellbore—this is followed by pumping heavy fluid (kill fluid) is pumped into the relief wellbore to suppress the high pressure in the original wellbore causing the blowout. |
Most directional drilling operations follow a well path that is predeter- mined by engineers and geologists before the drilling commences. When the drilling process is started, periodic surveys are taken with a downhole camera instrument (single shot camera) to provide survey data (inclination and azimuth) of the well bore—the pictures are typically taken at intervals between 30 and 500 ft (commonly 90 ft during active changes of angle or direction) and distances of 200 to 300 ft are more typical while drilling ahead (not making active changes to angle and direction). During criti- cal angle and direction changes, a MWD tool will be added to the drill string to provide continuously updated measurements that may be used for (near) real-time adjustments. The data acquired during the operation indicate whether or not the well is following the planned path and whether or not the orientation of the drilling assembly is causing the well to devi- ate as planned. Corrections are regularly made by techniques as simple as adjusting rotation speed or the drill string weight (weight on bottom) and stiffness, as well as more complicated and time consuming methods, such as introducing a downhole motor. |
Thus, directional drilling is used to: (1) to optimize drilling, as several wells and side tracks—that is, another well drilled using the upper part of the first well can be drilled from the same onshore site or marine platform, (2) to optimize the approach to the target, so that an increased interval of reservoir is crossed by the borehole with sloping or horizontal trajectory— the ultimate result is to improve the subsequent production, (3) to reach tar- gets that are located in zones not accessible by vertical drilling, (4) to cross faults, by choosing a direction close to perpendicular to the fault in order to minimize the drift effects that are induced on drilling by the fault, (5) to drill salt domes from lateral locations, which sometimes can be preferable to vertical drilling because of the problems involved in the drilling of the salt, and (6) to realize side tracking in wells partially damaged—this operation makes it possible to drill a borehole section parallel to an abandoned one. |
Until the arrival of modern downhole motors and better tools to mea- sure inclination and azimuth of the hole, directional drilling and horizontal drilling was much slower than vertical drilling due to the need to stop regularly and take time consuming surveys, and due to slower progress in drilling itself (lower rate of penetration). These disadvantages have shrunk over time as downhole motors became more efficient and semi-continuous surveying became possible. |
A disadvantage of wells with a high inclination was that prevention of sand influx into the well was less reliable and needed higher effort. Again, this disadvantage has diminished such that, provided sand control is ad- equate planned, it is possible to carry it out reliably. |
5.2.5Multilateral Drilling Technology |
During the 1990s, the technology of drilling branches in the reservoir was developed and technology enables the drilling of more than two wells (commonly three to six or up to eight production bores) out from a mother bore in the production zones of interest. In certain circumstances, the tech- nology has provided access to new reserves and allowed large reductions in overall well costs. |
A combination well is a well drilled for two purposes: (1) production from a thin oil zone and (2) gas production from a gas cap. The horizontal well section is suited to extracting oil from a thin oil layer, which in the illustrat- ed case has a gas cap above and a water zone below. Production from such a well can better be optimized with a low reservoir draw down, to avoid provoking the water to cone or gas to cusp into the wellbore prematurely. After production of the oil zone, gas can be produced through the higher perforations in order to avoid drilling a new well for the purpose. |
5.3SALT DEPOSITS |
Technology has provided access to areas that were either technically or economically inaccessible owing to major challenges, such as deposits located in very deep water or located below salt formations.While the major additions to production and reserves in the Gulf of Mexico have occurred in deep wa- ters, work in refining the discovery and recovery of oil and gas deposits in sub- salt formations must be noted as another promising area of potential supplies. |
Eighty-five percent of the continental shelf in the Gulf of Mexico, in- cluding both shallow- and deep-water areas, is covered by salt deposits, which comprises an extensive area for potential crude oil and natural gas development. Phillips Petroleum achieved the first subsalt commercial de- velopment in the Gulf of Mexico with its Mahogany platform. This plat- form, which was set in August 1996, showed that commercial prospects could be found below salt (in this case below a 4000 ft salt sheet). |
The subsalt accumulations can be found in structural traps below salt sheets or sills.The first fields under salt were found by directional wells drill- ing below salt overhangs extending out from salt domes. Experience in field development close to salt-covered areas indicated that not all salt features were simple dome-shaped features or solid sheets. Often the salt structure was the result of flows from salt deposits that extended horizontally over sedimentary formations that could contain oil. The salt then acts as an im- permeable barrier that entraps the crude oil and natural gas in accumula- tions that may be commercially viable prospects. |
The identification of structures below salt sheets was the first problem to overcome in the development of subsalt prospects, as the salt layers pose great difficulty in geophysical analysis. The unclear results did not provide strong support for investing in expensive exploratory drilling. The advent of high-speed parallel processing, pre- and post-stack processing techniques, and 3-D grid design helped potential reservoir resolution and identification of prospects. |
Industry activity in subsalt prospect development has been encouraged also by improvements in drilling and casing techniques in salt formations. Drilling through and below salt columns presents unique challenges to the drilling and completion of wells.The drilling of these wells requires special planning and techniques. Special strings of casing strategically placed are paramount to successful drilling and producing wells. |
The highly sophisticated technology available to firms for offshore operations does not necessarily assure success in their endeavors, and the subsalt prospects illustrate this point. The initial enthusiasm after the Ma- hogany project was followed by a string of disappointments in the pursuit of subsalt prospects. After a relative lull in activity industry-wide, Anadarko announced a major subsalt discovery in shallow water that should contain at least 140 million barrels of oil equivalent (BOE), with reasonable potential of exceeding 200 million BOE. Successes of this magnitude should rekindle interest in meeting the challenge posed by salt formations. |
Subsalt development has also been slowed because the majority of pros- pects have been leased or recovery from the subsalt is delayed by production activities elsewhere on a given lease. Subsalt operations apparently will be more a factor in the future as flows from leases presently dedicated to other production decline and the leases approach the end of their lease terms, which will promote additional development to assure continuation of lease rights. |
5.4WELL COMPLETION |
Once the final depth has been reached, the well is completed to allow oil to flow into the casing in a controlled manner. |
The well consists of a wellhead, which supports the well casing in the ground, and a pod (submerged Christmas tree, wet tree), which contains valves to control the flow and to shut off the flow in the case of an emergency or a leak in the riser. This pod Subsea wells are expensive, but not as expen- sive in deepwater as placing a platform at the site. If a subsea well ceases to produce, or if its rate of production falls below economic limits, it is neces- sary to bring in a mobile drilling unit to remove the tree and perform the workover.This can be an extremely expensive operation and if the outcome of the workover is in doubt, the operator may choose to abandon the well instead. Because of this, much of the oil and gas in reservoirs produced through subsea trees may be left behind. Subsea wells may also result in lower reservoir recovery simply because of the physics of their operation. The chokes and valves placed in a subsea tree result in a pressure drop in the flow of oil or gas. When the well formation drops below a certain thresh- old, production ceases to flow. The difference in cut-off pressure between a subsea well and a surface well can be as much as 1000 psi versus 100 psi. |
First, a perforating gun is lowered into the well to the production depth. The gun has explosive charges to create holes in the casing through which oil can flow. After the casing has been perforated, a small-diameter pipe (tubing) is run into the hole as a conduit for oil and gas to flow up the well and a packer is run down the outside of the tubing. When the packer is set at the production level, it is expanded to form a seal around the outside of the tubing. Finally, a multivalve structure (the Christmas tree; Figure 5.1) is installed at the top of the tubing and cemented to the top of the casing.The Christmas tree allows them to control the flow of oil from the well. |
The average rate of production from deep-water wells has increased as completion technology, tubing size, and production facility efficiencies have advanced. Less expensive and more productive wells can be achieved with extended reach, horizontal and multilateral wells. Higher rate completions are possible using larger tubing (5-in. or more) and high-rate gravel packs. Initial rates from Shell’s Auger Platform were about 12,000 barrels of oil per day per well.These flow rates, while very impressive, have been eclipsed by a well at BP’s Troika project on Green Canyon Block 244, which produced 31,000 barrels of oil on January 4, 1998. |
Another area of development for completion technology involves sub- sea well completions that are connected by pipeline to a platform that may be miles away. The use of previously installed platform infrastructure as central producing and processing centers for new fields allows oil and gas recovery from fields that would be uneconomic if their development re- quired their own platform and facilities. Old platforms above and on the continental slope have extended their useful life by processing deep water fields. A prime example of this innovation is the Mensa field, which gathers gas at a local manifold and then ships the gas by pipeline to the West Delta 143 platform 68 miles up the continental shelf. |
The exploitation of deep water deposits has benefited from technologi- cal development directed at virtually all aspects of operation. Profitability is enhanced with any new equipment or innovation that either increases productivity, lowers costs, improves reliability, or accelerates project devel- opment (hence increasing the present value of expected returns). In addi- tion to the major developments already discussed, other areas of interest for technological improvement include more reliable oil subsea systems (which include remotely operated vehicle systems), bundled pipeline installations of 5 miles or more that can be towed to locations, improved pipeline con- nections to floating and subsea completions, composite materials used in valving, and other construction materials. |
The advantages of adopting improved technology in deep water proj- ects are seen in a number of ways. For example, well flow rates for the Ursa project are 150% more than those for the Auger project just a few years earlier. The economic advantages from these developments are substantial as the unit capital costs were almost halved between the two projects. The incidence of dry holes incurred in exploration also has declined with direct reduction in project costs. The number of successful wells as a fraction of total wells has increased dramatically, which reflects the benefits of improve- ments in 3-D seismic and other techniques. Lastly, aggressive innovation has improved project development by accelerating the process from initial stages to the point of first production. Rapid development requires not only improvements in project management, but also better processes to allow construction of new facilities designed for the particular location in a timely fashion. Project development time had ranged up to 5 years for all offshore projects previously. More recent field development has been conducted in much less time, with the period from discovery to first production ranging between 6 and 18 months. Experience with deep-10 water construction and operations has enabled development to proceed much faster, with time from discovery to production declining from 10 years to just over 2 years by 1996. Accelerated development enhances project economics significantly by reducing the carrying cost of early capital investment, and by increasing the present value of the revenue stream. Design improvements between the Auger and Mars projects allowed Shell to cut the construction period to 9 months with a saving of $120 million. |
The completion of offshore wells for offshore petroleum production involves two steps (1) tubular casing lines the length of the well bore to ensure safe control of crude oil and natural gas, (2) natural gas flows to the surface under its own pressure, but oil may need to be coaxed to the surface. In fact, well completion for producing crude oil and natural gas from offshore loca- tions is very similar to the process used on dry land and similar principles may be employed, but generally in a smaller area. Crude oil and natural gas wells are prepared for production through a process called completion. In the first step, a production casing is cemented into the well bore. |
The casing—tubular steel pipe connected by threads and couplings— lines the total length of the well bore to ensure safe control of the crude oil and natural gas, prevent water entering the well bore and keep the rock formations from falling or collapsing into the well bore. Once the cement has set, the production tubing can be put in place. Production tubing is steel pipe that is smaller in diameter than the production casing. Production tub- ing was traditionally made up of joined sections of pipe, similar to the string of pipe used for drilling, but most offshore wells today use coiled tubing, a continuous, high-pressure-rated hollow steel cylinder. Production tubing is lowered into the casing and hangs from a sea floor installation called the wellhead.The wellhead has remotely operated valves and chokes that allow it to regulate the flow of oil and gas.The casing is then perforated to allow crude oil and natural gas to flow into the well.This is done with a perforat- ing gun, an arrow of shaped explosive charges that is lowered into the well. An electrical impulse fires the charges that perforate the casing, surrounding cement, and reservoir rock. |
Natural gas flows to the surface under its own pressure, but oil may need to be coaxed to the surface by pumping in the later stages of a well’s lifespan. In many crude oil and natural gas wells, the formation must also be stimulated by physical or chemical means. This procedure creates chan- nels beyond the perforations that allow crude oil and natural gas to flow back to the well.The two most common stimulation methods are acidizing and fracturing (also known as “fracking”). Acidizing involves injecting acids under pressure through the production tubing and perforations and into the formation. |
Fracking involves pumping a fluid, such as a water gel, down the hole under sufficient pressure to create cracks in the formation. Whether these techniques are used depends on a number of factors, including potential en- vironmental impacts as well as the geology of the reservoir. Subsea pipelines can be used to connect multiple offshore wells to processing and transporta- tion facilities. Subsea pipelines were used for the Cohasset-Panuke project and play a key role in the Sable Offshore Energy Project, which also uses a major subsea pipeline from the production area to onshore facilities. |
Once the final depth has been reached, the well is completed to allow oil to flow into the casing in a controlled manner. First, a perforating gun is lowered into the well to the production depth. The gun has explosive charges to create holes in the casing through which oil can flow. After the casing has been perforated, a small-diameter pipe (tubing) is run into the hole as a conduit for oil and gas to flow up the well and a packer is run down the outside of the tubing. When the packer is set at the production level, it is expanded to form a seal around the outside of the tubing. Finally, a multivalve structure (the Christmas tree; Figure 5.1) is installed at the top of the tubing and cemented to the top of the casing.The Christmas tree allows them to control the flow of oil from the well. |
Tight formations are occasionally encountered and it becomes neces- sary to encourage flow. Several methods are used, one of which involves setting off small explosions to fracture the rock. If the formation is mainly limestone, hydrochloric acid is sent down the hole to produce channels in the rock. The acid is inhibited to protect the steel casing. In sandstone, the preferred method is hydraulic fracturing. In this technique, a fluid with a viscosity high enough to hold coarse sand in suspension is pumped at very high pressure into the formation, fracturing the rock. The grains of sand remain, helping to hold the cracks open. |