Oil and Gas, Drilling for
OIL AND GAS, DRILLING FOR
After all the exploratory analyses, drilling determines whether the exploration geophysicist has accurately located the reservoir (exploratory drilling) and whether the sites chosen for drilling into the same reservoir are optimal for efficient production (developmental drilling). When an exploratory hole produces neither oil nor gas, it is capped and abandoned. But if it does yield oil or gas, it is readied for production and becomes a completed well. To extract oil and gas requires drilling a well.
Drilling a well involves much more than making a hole. It entails the integration of complex technologies, requiring the driller to make individual decisions related to unexpected pressure regimes, practices, and rock formations. The resulting well is the sole conduit to move fluids from a reservoir to the surface—a conduit that must last at least fifty years and be flexible enough in design to allow for the application of future production technologies.
Drilling operators must confront and solve extremely difficult technical, safety, and control problems as they bore through layers of subsurface rock to access oil- or gas-bearing strata. Furthermore, drilling must protect the geologic formation, the ultimate productive capacity of the well, and the surface environment. Drilling problems must first be diagnosed using the information or data that is transmitted from the bottom of the well to the surface, where the information is collected on the rig floor.
Depending on the depth of the well, this time lag can consume valuable time needed to address the problem—either technical or geological—before it becomes worse and/or causes drilling operations to stop. Drilling a well involves all types of technical, geological, and economic risks. The greatest economic risk occurs when drilling operations must be halted after time and money have been invested. This is the nature of the challenge faced during the drilling process.
When a well has been drilled and lined with pipe, the connection between the geological formation and the well must be established. Well "completion" includes installing suitable metal pipe or casing, cementing this casing using rock section isolation devices, and perforating the casing to access the producing zones. In some reservoirs, the geological conditions dictate that "stimulation" processes be applied to improve reservoir permeability or fluid conductivity of the rock, thereby facilitating production through the well bore.
With an understanding of the nature of the rocks to be penetrated, the stresses in these rocks, and what it will take to drill into and control the underground reservoirs, the drilling engineer is entrusted to design the earth-penetration techniques and select the equipment. Substantial investments are at stake. Drilling and completion costs can exceed $400,000 per well, and offshore operations can easily escalate to more than $5 million per well. However, overall per-well costs (adjusted for inflation) have been dropping, falling more than 20 percent between 1980 and 2000. This technology-driven gain in extraction efficiency has more than made up for the higher costs associated with the increasingly more geologically complex operations and deeper depths faced in trying to extract the remaining oil and gas resources.
In the United States, 85 percent of wells are drilled by independent oil and gas operators, more than 90 percent of whom employ fewer than twenty people. Therefore, U.S. oil and gas production is dependent on the economic health of independent producers to offset the rising tide of imported crude oil.
Drilling is indeed a high-risk investment. Even with modern technology, drilling successful ex-ploratory wells can be elusive. In the United States, for exploratory wells drilled more than a mile from production, the chance of striking hydrocarbons are about one in ten, and exceeds one in forty for drilling in unproven frontier areas. Because of these daunting odds, the ever-increasing complexity of recovery, and the dwindling resource base, most energy experts in the late 1970s and early 1980s projected that the price of crude oil would double, triple, or quadruple by 2000. This did not happen. Profound advances in drilling technology as well as in other exploration and production technologies have allowed the inflation-adjusted price of crude oil to remain stable through the twentieth century except for short-term price distortions caused by geopolitical turmoil or misguided policies.
THE EARLY METHODS
On August 27, 1859, at a depth of only 69.5 feet, Francis Drake drilled and completed the first well at Titusville, Pennsylvania. By the end of the nineteenth century there were about 600,000 oil wells in more than 100 countries, with the United States and Russia dominating world production. In the United States, drilling was concentrated in the Appalachian oil fields until the Beaumont Texas, Spindletop Hill discovery on January 10, 1901, which then shifted exploration and production to the Southwest.
The world's largest petroleum reserves, in Turkey and the Middle East, were discovered just prior to World War I. Exploration and production continued to expand throughout the region in the 1920s, and culminated in the discovery of the vast oil resources of Saudi Arabia in 1938.
Early methods entailed cable-tool drilling. This crude impact-type drilling involved dropping a weighted bit by a cable and lever system to chisel away at the rock at the bottom of the hole. Periodically drilling had to be stopped to sharpen the bit and remove rock fragments and liquids from the bottom of the hole with a collecting device attached to the cable. Removal of liquids was necessary so the bit could more effectively chip away at rock. This dry method created the well-recognized "gusher," since a dry borehole allowed oil and gas to flow to the surface from the pressure of natural gas and water once the bit penetrated a producing reservoir. Usually considerable oil and "reservoir energy" were wasted until the well could be capped and controlled.
Rotary drilling became the preferred method of drilling oil and gas wells in the middle of the twentieth century (Figure 1). Using this method, the drill bit rotates as it pushes down at the bottom of the hole much like a hand-held power drill. Unlike in cable-tool drilling, the borehole is kept full of liquid during rotary drilling for two important reasons: The drilling mud circulates through the borehole to carry crushed rock to the surface to keep drilling continuous, and once the bit penetrates the reservoir, it does not create a gusher.
To drill a well, a site is selected and prepared. A drilling rig is transported to the site and set up. A surface hole is drilled, followed by drilling to the total planned depth of the well. The well is then tested, evaluated, and completed. Finally, production equipment is installed, and the well is put on production.
Drill-Site Selection and Preparation
Selection of the drill site is based largely on geological evidence indicating the possible accumulation of petroleum. The exploration drilling company wants to drill the well at the most advantageous location for the discovery of oil or gas. However, surface conditions also must be taken into consideration when selecting the drill site. There must be a nearly level area of sufficient size on which to set up the drilling rig, excavate reserve pits, and provide storage for all the materials and equipment that will be needed for the drilling program. All required legal matters must have been attended to, such as for acquiring a drilling permit and surveying of the drill site. When all of these matters have been resolved, work on site preparation will begin. Once the drill site has been selected and surveyed, a contractor or contractors will move in with equipment to prepare the location. If necessary, the site will be cleared and leveled. A large pit will be constructed to contain water for drilling operations and for disposal of drill cuttings and other waste. Many environmental regulations guide these practices. A small drilling rig, referred to as a dry-hole digger, will be used to start the main hole. A large-diameter hole will be drilled to a shallow depth and lined with conductor pipe. Sometimes a large, rectangular cellar is excavated around the main borehole and lined with wood. A smaller-diameter hole called a "rat hole" is drilled near the main borehole. The rat hole is lined with pipe and is used for temporary storage of a piece of drilling equipment called the "kelly." When all of this work has been completed, the drilling contractor will move in with the large drilling rig and all the equipment required to drill the well.
The components of the drilling rig and all necessary equipment are moved onto the location with large, specially equipped trucks. The substructure of the rig is located and leveled over the main bore-hole. The mast or derrick is raised over the substructure, and other equipment such as engines, pumps, and rotating and hoisting equipment, are aligned and connected. The drill pipe and drill collars are laid out on racks convenient to the rig floor so that they may be hoisted when needed and connected to the drill bit or added to the drill strings. Water and fuel tanks are filled. Additives for the drilling fluid (drilling mud) are stored on location. When all these matters have been attended to, the drilling contractor is ready to begin drilling operations ("spud the well").
The drill string, consisting of a drill bit, drill collars, drill pipe, and kelly, is assembled and lowered into the conductor pipe. Drilling fluid, better known as drilling mud, is circulated through the kelly and the drill string by means of pipes and flexible hose connecting the drilling fluid or mud pumps and a swivel device attached to the upper end of the kelly. The swivel device enables drilling mud to be circulated while the kelly and the drill string are rotated. The mud pump draws fluid from mud tanks or pits located nearby. The drilling mud passes through the kelly, drill pipe, drill collars, and drill bit. The drilling mud is returned to the surface by means of the well bore and the conductor pipe where it is directed to a shale shaker, which separates the drill cuttings and solids from the drilling mud, which is returned to the mud tanks to be recirculated. As the drill string is rotated in the well bore, the drill bit cut into the rock. The drilling mud lubricates and cools the drill bit and the drill string and carries the drill cuttings to the surface.
Drilling the Surface Hole
When a well is spudded in, a large-diameter drill bit is used to drill to a predetermined depth to drill the surface hole, which is lined with casing. The casing protects aquifers that may contain freshwater, provides a mounting place for the blowout preventer, and serves as the support for the production casing that will be placed in the well bore if the drilling program is successful. The surface hole may be several hundred or several thousand feet deep. When the predetermined depth is reached, the drill string will be removed from the well bore. Steel casing of the proper diameter is inserted. Sufficient cement is pumped down the surface casing to fill the space between the outside of the casing and the well bore all the way to the surface. This is to ensure protection of freshwater aquifers and security of the surface casing. The casing and the cement are tested under pressure for twelve hours before drilling operations may be resumed. The blowout preventer is attached at the top of the surface casing. This device is required to control the well in the event that abnormal pressures are encountered in the borehole that cannot be controlled with drilling fluid. If high-pressure gas or liquid blows the drilling fluid out of the well bore, the blowout preventer can be closed to confine the gas and the fluid to the well bore.
Drilling to Total Depth
After the surface casing has been tested and the blowout preventer installed, drilling operations are resumed. They will continue until the well has been drilled to the total depth decided upon. Usually the only interruptions to drilling operations will be to remove the drill string from the well bore for the replacement of the drill bit (a procedure known as tripping) and for testing of formations for possible occurrences of oil or gas (known as drill-stem testing). Other interruptions may be due to problems incurred while drilling, such as the shearing off the drill string (known as "twisting off") and loss of drill-bit parts in the well bore (known as "junk in the hole").
As drilling operations continue, a geologist constantly examines drill cuttings for signs of oil and gas. Sometimes special equipment known as a mud logger is used to detect the presence of oil or gas in the drill cuttings or the drilling fluid. By examining the drill cuttings, a geologist determines the type of rock that the drill bit is penetrating and the geologic formation from which the cuttings are originating.
Today's conventional drill bit utilizes three revolving cones containing teeth or hardened inserts that cut into the rock as the bit is revolved. The teeth or inserts chip off fragments of the rock which are carried to the surface with the drilling fluid. The fragments or chips, while they are representative of the rock being drilled, do not present a clear and total picture of the formation being drilled or the characteristics of the rock being penetrated as to porosity and permeability. For this purpose a larger sample of the rock is required, and a special type of drill bit is used to collect the sample, called a core. The core is usually sent to a laboratory for analysis and testing.
If the geologist detects the presence of oil or gas in the drill cuttings, a drill-stem test is frequently performed to evaluate the formation or zone from which the oil show was observed. Drill-stem tests may also be performed when the driller observes a decrease in the time required to drill a foot of rock, known as a "drilling break." Since porous rock may be drilled easier than nonporous or less porous rock, a drilling break indicates the presence of the type of rock that usually contains oil or gas. A drill-stem test enables the exploration company to obtain a sample of the fluids and gases contained in the formation or interval being tested as well as pressure information. By testing the well during the drilling phase, a decision as to whether to complete it can be made. When the well has been drilled to the predetermined depth, the drill string will be removed from the well bore to allow insertion of tools that will further test the formation and particularly the well. These tools are suspended on a special cable. Specific properties of the formation are measured as the tools are retrieved. Signals detected by the tools are recorded in a truck at the surface by means of the electrical circuits contained in the cable.
Completing the Well
When drill-stem testing and well logging operations have been completed and the results have been analyzed, company management must decide whether to complete the well as a producing well or to plug it as a dry hole. If the evidence indicates that no oil or gas is present, or that they are not present in sufficient quantity to allow for the recovery of drilling, completion, and production costs and provide a profit on investment, the well probably will be plugged and abandoned as a dry hole. On the other hand, if evidence indicates the presence of oil or gas in sufficient quantity to allow for the recovery of the cost and provide a profit to the company, an attempt will be made to complete the well as a producing well. The casing is delivered and a cementing company is called in.
The well bore is filled with drilling fluid that contains additives to prevent corrosion of the casing and to prevent movement of the fluid from the well bore into the surrounding rock. The casing is threaded together and inserted into the well bore in much the same manner as the drill string. Casing may be inserted to the total depth of the hole, or a cement plug may have been set at a specific depth and the casing set on top of it. Cement is mixed at the surface, just as if the well were to be plugged. The cement is then pumped down the casing and displaced out of the bottom with drilling fluid or water. The cement then flows up and around the casing, filling the space between the casing and the well bore to a predetermined height. After cementing of the casing has been completed, the drilling rig, equipment, and materials are removed from the drill site. A smaller rig, known as a workover rig or completion rig, is moved over the well bore. The smaller rig is used for the remaining completion operations. A well-perforating company is then called to the well site. It is necessary to perforate holes in the casing at the proper depth to allow the oil and the gas to enter the well bore. The perforating tool is inserted into the casing and lowered to the desired depth on the end of a cable. Shaped charges are remotely fired from the control truck at the surface, and jets of high-temperature and high-velocity gas perforate the casing, the cement, and the surrounding rock for some distance away from the well bore.
A smaller-diameter pipe, called tubing, is then threaded together and inserted into the casing. If it is expected that oil or gas will flow to the surface via the pressure differential between the well bore and the formation, a wellhead is installed; it is equipped with valves to control the flow of oil or gas from the well. The wellhead is known as a "Christmas tree." If there is not sufficient pressure differential to cause the oil and the gas to flow naturally, pumping equipment is installed at the lower end of the tubing.
During well completion it is sometimes desirable or necessary to treat or "stimulate" the producing zone to improve permeability of the rock and to increase the flow of oil or gas into the casing. This may be accomplished by use of acid or by injection of fluid and sand under high pressure to fracture the rock. Such a treatment usually improves the ability of the rock to allow fluid to flow through it into the well bore. At this point the drilling and completion phases have ended.
The Drill Bits and Well Design
Designing more effective and durable drill bits is important because drilling depths of reservoirs can reach as deep as 5 mi (8,052 m). Worldwide use of the more expensive polycrystalline diamond compact (PDC) drill bit has slowly been gaining on the conventional roller cone bit because of faster rates of penetration and longer bit life. The 1998 PDC bit rotated 150 to 200 percent faster than similar bits a decade earlier, and averaged more than 4,200 ft (1,281 m) per bit as opposed to only 1,600 ft (488 m) per bit in 1988. This 260 percent improvement dramatically cuts time on site since the less often the drill bit needs changing, the less time and energy must be devoted to raising and lowering drill pipe. It also means that the 15,000-ft well in the 1970s that took around eighty days could be completed in less than forty days in 2000. Because wells can be drilled more quickly, more profitably and with less of an environmental impact, the total footage drilled by diamond bits went from about 1 percent in 1978 to 10 percent in 1985 and to 25 percent in 1997.
To reduce drilling and development costs, slimhole drilling is increasingly being used. Slimhole wells are considered wells in which at least 90 percent of the hole has been drilled with a bit fewer than six inches in diameter. For example, a typical rig uses a 8.5-in bit and a 5-in drill pipe, whereas a slimhole rig may use a 4-in bit and a 3.7-in drill pipe. Slimhole drilling is especially valuable in economically marginal fields and in environmentally sensitive areas, since the fuel consumption can be 75 percent less (mud pumps, drill power), the mud costs 80 percent less, the rig weight is 80 percent less, and the drill site is 75 percent smaller.
Another important advance for developmental drilling is coiled tubing technology. Often used in combination with slimhole drilling technology, coiled tubing is a continuous pipe and thus requires only about half the working space as a conventional drilling pipe operation. Moreover, coiled tubing eliminates the costs of continuous jointing, reinstallation and removal of drill pipe. Since the diameter of coiled tubing is smaller than that of conventional pipe, coiled tubing also reduces operational energy use, noise, and the quantity of mud generated. The material of choice is currently steel, yet titantium is slowly replacing steel because titanium's greater strength promises a life cycle five to ten times longer than steel.
In weak formations or where groundwater needs to be protected, the borehole is lined with casing to prevent any transfer of fluids between the borehole and its surroundings. Strings of casing are progressively smaller than the casing strings above it, and the greater the depth of the well, the more casing sizes used. For very deep wells, up to five sizes of ever smaller diameter casings are used during the drilling process. This tiered casing approach has not only reduced the volume of wastes but also has been refined so that drilling cuttings can be disposed of by reinjecting them into the area around the borehole between the surface casing and the intermediate casing (Figure 2). In this way, wastes are returned to the geologic formations far below the surface, eliminating the need for surface disposal, including waste management facilities, drilling waste reserve pits, and off-site transit transportation.
Drilling is not a continuous operation. Periodically drilling must stop to check bottomhole conditions. To reduce the time lag between occurrence and surface assessment, measurement-while-drilling (MWD) systems are increasingly being used to measure downhole conditions for more efficient, safer, and accurate drilling. These systems transmit real-time data from the drill bit to the surface by encoding data as a series of pressure pulses in the mud column that is then decoded by surface sensors and computer systems. The accelerated feedback afforded by MWD systems helps keep the drill bit on course, speeds reaction to challenging drilling operations (high-pressure, high-temperature and underbalanced drilling), and provides valuable and continual clues for zeroing in on the reservoir's most productive zones. Since MWD systems provide a faster and more accurate picture of formation pore pressure and fracture pressure while the well is being drilled, it also substantially reduces the risks of life-threatening blowouts and fires.
HORIZONTAL, DIRECTIONAL AND MULTILATERAL DRILLING
Horizontal and directional drilling are non-vertical drilling that allow wells to deviate from strictly vertical by a few degrees, to horizontal, or even to invert toward the surface (Figure 3). Horizontal drilling is not new. It was first tried in the 1930s, but was abandoned in favor of investing in hydraulic fracturing technology (first introduced in 1947) that made vertical wells more productive. Rebirth of horizontal drillings began in the mid-1970s due to the combination of steerable downhole motor assemblies, MWD systems, and advances in radial drilling technology that made horizontal drilling investments more cost-effective. In 1996 more than 2,700 horizontal wells were dug, up from a very minimal number only a decade earlier.
In the simplest application, the borehole begins in a vertical direction and then is angled toward the intended target. The drill pipe still needs to move and rotate through the entire depth, so the deviation angle of the borehole needs to be gradual. A large deviation is made up of many smaller deviations, arcing to reach the intended target. The redirection of drill pipe is accomplished by use of an inclined plane at the bottom of the borehole. More recently, greater precision in directional drilling has been accomplished by using a mud-powered turbine at the bottom to drill the first few feet of the newly angled hole.
Horizontal and directional drilling serves four purposes. First, it is advantageous in situations where the derrick cannot be located directly above the reservoir, such as when the reservoir resides under cities, lakes, harbors, or environmentally sensitive areas such as wetlands and wildlife habitats. Second, it permits contact with more of the reservoir, which in turn means more of the resource can be recovered from the single well. Third, it makes possible multilateral drilling—multiple offshoots from a single borehole to contact reservoirs at different depths and directions. Finally, horizontal drilling improves the energy and environmental picture, since there is less of an environmental impact when fewer wells need to be drilled, and the energy future is brighter since more oil can be expected from any given well. Horizontal drilling has been credited with increasing the United States oil reserves by close to 2 percent or 10 billion barrels. Although horizontal drilling is more expensive than vertical drilling, the benefits of increased production usually outweigh the added costs.
Since oceans and seas cover more than two-thirds of the Earth, it came as no surprise when oil was discovered ten miles off the Louisiana coast in 1947. Fifty years later, offshore production had grown to approximately a third of all world output, most coming from the North Sea, the Persian Gulf, and the Gulf of Mexico. Technology has evolved from shallow-water drilling barges into fixed platforms and jack-up rigs, and finally into semisubmersible and floating drill ships (Figures 4–7). Some of these rigs are among the largest and most massive structures of modern civilization. And because drilling often takes place in waters as deep as 10,000 ft (more than 3,080 m) deep, as far as 200 mi (more than 300 km) from shore, and in unpredictable weather (it must be able to withstand hurricanes and uncontrollable releases of oil), the challenges facing designers, builders, and users of these rigs are daunting.
Offshore drilling operations entail much of the same technology as land-based drilling. As with onshore drilling, the offshore drill pipe must transmit rotary power and drilling mud to the bit for fixed rigs, floating rigs, and drill ships. Since mud also must be returned for recirculation, a riser (a flexible outer casing) extends from the sea floor to the platform. As a safety measure—to contend with the stress created from the motion and movement of the boat in relation to the sea bottom—risers are designed with material components of considerable elasticity.
Besides the much grander scale of offshore rigs, there are numerous additional technologies employed to contend with deep seas, winds, waves, and tides. The technical challenges include stability, buoyancy, positioning, mooring and anchoring, and rig designs and materials that can withstand extremely adverse conditions.
Shallow Water and Arctic Areas
For shallow-water drilling, usually water depths of 50 ft (15.4 m) or less, a drilling platform and other equipment is mounted on a barge, floated into position, and sunk to rest on the bottom. If conditions dictate, the drilling platform can be raised above the water on masts. Either way, drilling and production operations commence through an opening in the barge hull.
For drilling in shallow water Arctic environments, there is an added risk from the hazard of drifting ice. Artificial islands need to be constructed to protect the platform and equipment. Because of permafrost, drilling onshore in Arctic regions also necessitates building artificial islands. These usually are built from rock and gravel so that the ground does not become too unstable from permafrost melting around the drill site. To leave less of an environmental footprint, these artificial islands are increasingly being built from ice pads rather than gravel. Because the ice pads are insulated to prevent thawing, the drilling season in some Arctic areas has been extended to 205 days, and well operations to as long as 160 days. This heightens the chances of single-season completions that dramatically reduce costs, since equipment does not need to be removed to nontundra areas and brought back again.
For deeper drilling in open waters over the continental shelves, drilling takes place from drill ships, floating rigs and rigs that rest on the bottom. Bottom-resting rigs are mainly used for established developmental fields (up to 3,000 ft or 924 m); the semisubmersible and free-floating drill ships (up to 10,000 ft or 3,080 m) are the primary choice for exploratory drilling.
Where drilling and production are expected to last a long time, fixed rigs have been preferred. These rigs stand on stilt-like legs imbedded in the sea bottom and usually carry the drilling equipment, production equipment, and housing and storage areas for the work crews.
The jack-up platform, which is most prevalent, is towed to the site and the rack-and-pinion geared legs are cranked downward toward the bottom. Once the legs are stabilized on the bottom with pilings, the platform is raised 30 to 60 ft (9.2 to 18.5 m) above the surface. Another common fixed rig rests on rigid steel or concrete bases that are constructed onshore to the correct height. The rig is then towed to the drilling site, where the flotation tanks, built into the base, are flooded to sink the base to the ocean floor. For drilling in mild seas, a popular choice is a tenderassisted rig, where an anchored barge or tender is positioned alongside the rig to help with support. The hoisting equipment sits on the rig, with all the other associated support equipment (pumps, generators, cement units, and quarters) on the barge.
As more offshore exploratory operations move into deeper water—in 1997 there were thirty-one deep water rigs drilling in water depths greater than 1,000 ft (305 m) as opposed to only nine in 1990— there is sure to be more growth in the use of semisubmersible rigs and drill ships. In rough seas, semisubmersible drilling rigs are the preferred option since the hull is entirely underwater, giving the rig much more stability. The operational platform is held above the surface by masts extended upward from the deck. Cables are moored to the sea floor, with the buoyancy of the platform creating a tension in the cables that holds it in place.
When seas are less treacherous and there is greater need for mobility and flexibility, the drill ship is preferred over the semisubmersible. The drill ship has a derrick mounted in the middle over an opening for drilling operations, with several moorings used to hold the ship in position.
The use of dynamic positioning systems, instead of using moorings and cables, is becoming more popular in situations where it is expensive or extremely difficult to set and remove mooring lines. With the aid of advanced monitoring systems—gyrocompass wind sensors, global positioning systems, underwater sonar beacons, and hydroacoustic beacons—precise directional thrust propellers are used to automatically hold the vessel's orientation and position over the borehole. Despite the forces of wind, waves and ocean currents, at a water depth of 5,000 ft (1,526 m), a dynamic positioning system can reliably keep a drill ship within 50 ft (15.2 m) of the spot directly over the borehole.
As larger offshore discoveries become harder to find, more attention will be directed toward maximizing development from existing known reserves (workovers and recompletions), which seems to ensure a future for self-contained and jack-up rigs. There are certain to be reductions in size and weight of these new rigs. Self-elevating telescoping masts, which have improved dramatically in the 1990s, will become lighter and install more quickly. There also will be efficiency gains in equipment, and setup will be quicker, since modular units are becoming smaller, lighter, and less bulky.
The frontier remains deep water. Since the trend is toward longer-term operations, the design and materials of rigs that rest on the sea bottom will need to improve to handle the increased loads the extended reach needed in greater water depths. Productivity also will be increasing, since some of the latest ships can conduct simultaneous drilling operations using two drilling locations within a single derrick. Furthermore, because the costs of building and transporting massive drilling rigs can easily exceed several billion dollars, material research will continue to look for ways to prolong rig life cycles, and ways to better test structures regularly to avoid a catastrophic collapse. In particular, better welds, with fewer defects, will greatly extend the life cycle of offshore platforms from the continual forces of wind, waves, and ocean currents.
ANOTHER EQUIPMENT USE: CARBON DIOXIDE AND METHANE SEQUESTRATION
Since methane (CH4) and carbon dioxide (CO2) are greenhouse gases that governments of the world want reduced, the oil and gas industry—a major emitter of both—is looking for ways to effect such reductions. During drilling and production for oil and gas, significant amounts of CO2 and CH4 are produced. Where it is uneconomical to produce natural gas, this "stranded gas" is either vented as methane, flared (about 95% conversion to CO2), converted to liquids (liquefied natural gas or methanol), or reinjected into the well. Over half of the oil exploration and production CO2 emissions come from flaring, and almost all the methane emissions come from venting. The industry is trying to reduce emissions of both by better flare reduction practices, focusing on ways to convert more stranded gas to liquid fuels, and developing vapor recovery systems.
Another problem is when the carbon dioxide content of natural gas is too high and must be lowered to produce pipeline-quality gas. Although the current practice is to vent this CO2, sequestration of CO2 in underground geologic formations is being considered. Already, in the Norwegian sector of the North Sea, CO2 has been injected into saline aquifers at a rate of 1 million tons a year to avoid paying the Norwegian carbon tax of $50 per ton of CO2.
It may turn out that the same drilling technology that is being used to extract oil and gas, and that has been adapted for mining, geothermal, and water supply applications, will someday be equally useful in sequestering CO2 in appropriate subsurface geologic formations.
John Zumerchik Elena Melchert
See also:Climatic Effects; Fossil Fuels; Gasoline and Additives; Governmental Intervention in Energy Markets; Liquefied Petroleum Gas; Methane; Natural Gas, Processing and Conversion of; Natural Gas, Transportation, Distribution, and Storage of; Oil and Gas, Exploration for; Oil and Gas, Production of; Risk Assesment and Management.
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Benefits of Advanced Oil and Gas Exploration and Production Technology. (1999). Washington DC: United States Department of Energy.
Carter, G. (2000). "Offshore Platform Rigs Adapting to Weight-Space Restrictions for Floaters." Offshore 60(4).
Devereux, S. (2000). Drilling Technology. Tulsa, OK: PennWell.
Drilling for Oil, Unit 4: Activity 4-4/Teacher, pp. 4–48 to 4–53. Washington, DC: Teacher Training Program, National Petroleum Technology Office, Office of Fossil Energy, U.S. Department of Energy.
Hyne, N. J. (1995). Nontechnical Guide to Petroleum Geology, Exploration, Drilling and Production. Tulsa, OK: PennWell.
Pratt, J. A.; Priest, T.; and Castaneda, C. J. (1997). Offshore Pioneers: Brown & Root and the History of Offshore Oil and Gas. Houston, TX: Gulf Publishing Company.
U.S. Department of Energy. (1999). Securing the U.S. Energy Environmental, and Economic Future. Washington, DC: Author.
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