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Conventional Petroleum, Enhanced Oil Recovery, and Natural Gas Over geologic time oil and gas have accumulated in porous rock forma- tions called reservoirs, where they are hydrodynamically trapped by overly- ing and adjacent impermeable rock. The origins of these hydrocarbons are generally believed to be plant and animal life buried millions of years ago and slowly transformed by pressure and temperature into oils and gases of various qualities. The oil or gas resides together with varying amounts of water in microscopic pore spaces within the reservoir rock. Reserves are the amounts of oil or gas believed to be economically re- coverable from a reservoir through the use of existing technology. This seemingly simple concept is, in fact, quite complicated. When a discovery well penetrates a new reservoir, it provides very little information about the complex geologic character of the reservoir and its contained fluids. Only after extensive drilling and production over time can the extent of the re- serves be estimated with significant accuracy. Production rates from reservoirs depend on a number of factors, such as reservoir pressure, rock type and permeability, fluid saturations and proper- ties, extent of fracturing, number of wells, and their locations. Operators can increase production over that which would naturally occur by such methods as fracturing the reservoir to open new channels for flow, injecting gas and water to increase the reservoir pressure, or lowering oil viscosity with heat or chemicals. These supplementary techniques are expensive, and the extent to which they are used depends on such external factors as the operator's economic condition, sales prospects, and perceptions of future prices. The extraordinary geological variability of different reservoirs means that production profiles differ from field to field (for illustrative purposes see Figure 2-1~. Oil reservoirs can be developed to significant levels of 21
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22 FUELS TO DRIVE OUR FUTURE O O ~ ~ O O ~ an O _ ~ ~ O a Production / Production Secondary \ Continues / Production o / ~ \ Field / \ Abandoned 15 20 25 TIME (years) FIGURE 2-1 Production profiles of typical oil and gas reservoirs whose production is not limited by market consent or government regulation. Oil flows generated by natural geological pressures are called primary production. Secondary produc- tion results from supplementary actions, such as water injection into the reservoir. production and maintained for a period of time by supplementing natural drive force, while gas reservoirs normally decline more rapidly. On this basis an oil reservoir with the seemingly large reserve of a million barrels might produce only 200 to 400 bbl/day during its best years. Against a U.S. consumption of roughly 17 MMbbl/day of oil, that is indeed only a modest contribution. Nevertheless, a very large number of small U.S. reservoirs account for a significant part of domestic petroleum production. The bulk of low-cost worldwide oil reserves is located in countries be- longing to the Organization of Petroleum Exporting Countries (OPEC) (EIA, 1989a). Furthermore, because the marginal cost of production in OPEC is lower in comparison to costs in other countries, OPEC could exert major influences on oil prices. However, the United States has significant petro- leum resources and an oil industry infrastructure that has shown it is ca- pable of replacing reserves when the economic climate stimulates it to do so. The U.S. oil and gas industry can be divided into upstream operations, which are concerned with exploring for and producing oil and gas, and downstream operations, which deal with transportation, refining, distribu- tion, and marketing. Upstream operations were hardest hit by the 1986 and 1988 world oil price collapses.
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CONVE=IONAL PETROLEUM 23 In 1985 the U.S. upstream sector was a huge economic enterprise em- ploying more than 600,000 people with sales of well over $500 billion (API Basic Petroleum Data Book 1986; Oil and Gas Journal, 1986~. Participants included the domestic operations of a dozen major oil companies with 1985 net incomes of more than $15 billion; over 20,000 independent oil and gas explorers and producers; hundreds of oil field service companies who pro- vided seismic surveys, drilling, logging, fracturing, and other services; and a large array of suppliers of pipe, pumps, compressors, computers, chemi- cals, and other equipment and supplies (Oil and Gas Journal, 1986~. Cur- rently, this enterprise is dramatically smaller in size. The search for oil and gas is risky and expensive. For example, a pros- pect with a million barrels of reserve, which is considered to be relatively small "stakes," might cost several million dollars for people, land, geologi- cal and geophysical surveys, drilling, and testing. The likelihood of suc- cess—the "chance factor"—of such a relatively modest endeavor might range typically from 10 to 40 percent depending on the geographic proximity to other production. Chance factors for higher-stakes, larger targets can range from 5 to 20 percent. The most recent, famous, expensive high-stakes exploration failure was the 1984 Mukluk prospect in the Alaskan Beaufort Sea. It cost about $1.5 billion, and no commercial oil or gas was discov- ered. Although predrilling geological and geophysical techniques for finding oil and gas have become increasingly more sophisticated in recent years, they are still far from providing clear images of the subsurface, including identifying the presence of oil and gas. There is no substitute for drilling a well to confirm geological models and to establish the presence of hydro- carbons. On this basis the number of drilling rigs operating at any particu- lar time the "rig count"—is an important measure of U.S. upstream activ- ity. There are different kinds of wells drilled in upstream operations. A development well is drilled to enable increased production from a known reservoir. It is not planned to increase reserves; however, it generally increases hydraulic communication with the reservoir units and often re- sults in reserve appreciation. In geologically complex reservoir systems, targeted infill (drilling within a known field) development wells can signifi- cantly increase reserves. An extension exploration well is aimed at finding a new reservoir near an area of known production. An extension well can have a relatively high chance of success 30 to 60 percent" because of its proximity to known production. Finally, there is wildcat exploration drilling. This is done in areas where there may be no subsurface information from existing wells. Wildcat ex- ploration is the most risky drilling. During the two decades from 1960 to 1979, only 1 to 2 percent of the U.S. wildcat wells yielded significant new fields with reserves greater than 1 MMbbl of oil or 6 Bcf of gas; however, .
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24 FUELS TO DRIVE OUR FUTURE 10 to 16 percent of such wells yielded enough oil or gas to be brought into commercial operation. Thus, while rig count is a significant measure of industry activity, it is important to understand the types of holes being drilled. If the wells being drilled are developmental ones, the national re- serve base will soon be more rapidly decreased as production from these wells depletes reserves. If there is a significant amount of exploration and targeted extension drilling, the national reserve base will be supplemented with additions. The recent decline in U.S. drilling activity, coupled with a shift to development drilling, will assuredly lead to a dramatic reduction in U.S. oil and gas production in the years ahead. Unless this is intentionally changed by increased domestic drilling and improved recovery technology, the United States can expect an increasing reliance on imported petroleum. REMAINING DOMESTIC OIL AND GAS RESOURCES Over time, judgments of volumes of U.S. oil and gas available for dis- covery, further development, and recovery have changed. Estimates of re- maining resources made from 1900 to 1940 later proved to be exceedingly low. The sustained discovery of giant oil and gas fields from the 1920s through the middle 1950s led to more optimistic estimates of ultimate dis- covery and recovery. However, by the 1950s most of the onshore giant fields in the lower 48 states had been discovered and new field discovery of oil and natural gas had peaked. This peaking, preceded by an exponential increase in discovery, led Hubbert (1962) to postulate a symmetrical life cycle of both discovery and subsequent production. He believed that after peaking, discovery rates and, later, production rates would decline exponen- tially. Physically constrained, technology and economics could modify only slightly the volume of ultimate recovery. The volume of ultimate recovery was estimated using this model, and it was projected that production in the continental United States would peak in the early 1970s. When production did peak in the early 1970s and then declined through the rest of the decade, the remaining U.S. oil and gas resource was generally perceived to be shrink- ing and depleting rapidly. Significant increases in wellhead prices for oil and natural gas through the 1970s and early 1980s led to a major increase in drilling. During this time approximately 45 percent of all gas wells and 30 percent of all U.S. oil wells were drilled and completed. This major pursuit of a resource base, which was judged marginal and rapidly depleting, showed unexpected re- sponse. Finding rates, expressed in volumes of oil and gas discovered per foot of exploratory drilling, though lower than those of the early days of exploration, remained stable. The rates did not decline exponentially with cumulative drilling as anticipated. Reserve growth from the extensive and
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CONVENTIONAL PETROLEUM 25 intensive drilling of many older oil fields, generally judged to be fully appreciated by historical field development, was much greater than expected. By 1985 production in the continental United States was nearly 7.2 MMbbl/ day—2 MMbbVday more than projected using the exponential decline model. While this had the appearance of only arresting decline and stabilizing production, it actually represented a nearly 40 percent increase over pro- jected production capacity from a resource once judged to be nearly ex- hausted. Estimates of ultimate recovery and production in the lower conti- nental United States, earlier reported using the symmetrical life-cycle view of resource behavior, have already been exceeded. Contrary to conventional wisdom, the growing view in 1989 was that the remaining U.S. resource base of oil and gas is substantial and sufficient to slow the rate of decline in production and maintain significant oil produc- tion for three to five decades at moderate and stable real prices. Remaining U.S. resources, like the resources pursued in recent years, will generally be converted to producible reserves in small to moderate-size increments. Remaining large reserve increments are largely restricted to the relatively high-cost frontier areas, including Alaska and the deep water offshore, at- tractive areas for the industry to explore. Oil Resources Two recent estimates of remaining U.S. oil resources have been made: one by the American Association of Petroleum Geologists (AAPG, 1989a) and the other by ICF Resources in their report to this committee (Table 2-1) (Kuuskraa et al., 1989~. The ICF analysis incorporated estimates by the U.S. Department of the Interior (DOI) (U.S. Geological Survey LUSGS] for onshore and the Minerals Management Service EMMS] for offshore) of undiscovered resources in 1989 (U.S. DOI, 1989~. Differences in proved reserves and reserve growth resource estimates made by AAPG and ICF Resources under assumptions of moderate cost ($25/barrel, 1986 dollars,assumedby AAPG; $24/barrel, 1988 dollars, as- sumed by ICF), moderate cost with advanced technology, and high cost ($50/barrel, 1986 dollars, assumed by AAPG; $40/barrel, 1988 dollars, as- sumed by ICF) are very slight when adjustments are made for the different real price assumptions. With the high-cost and advanced technology cate- gory, the difference in the two estimates is substantial, even allowing for the 38 percent difference in price assumptions. Obviously there is no his- torical experience with prices at either of the high-cost levels assumed. When this is combined with assumptions about advanced technology, the range of uncertainty is expectedly high. The principal difference in the two estimates lies in judgments of vol- umes of undiscovered oil at the assumed price levels. The larger volumes
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26 FUELS TO DRIVE OUR FUTURE TABLE 2-1 Recent Estimates of U.S. Oil Resources (billion barrels) AAPG (1989) ICF Resourcesa (1989) Moderate Costs Proved reserves 27.0 27.3 Reserve growthb 17.0 35.9 Undiscovered 33.0 12.4 Total 77.0 75.6 Moderate Costs with Advanced Technology Proved reserves 27.0 27.3 Reserve growth 62.0 69.2 Undiscovered 40.0 18.5 Total 129.0 115.0 High Costs Proved reserves 27.0 27.3 Reserve growth 53.0 46.6 Undiscovered 60.0 20.5 Total 140.0 94.4 High Costs with Advanced Technology Proved reserves 27.0 27.3 Reserve growth 150.0 82.7 Undiscovered 70.0 30.1 Total 247.0 140.1 aModerate costs assumed by AAPG were $25/barrel in 1986 dollars; mod- erate costs assumed by ICF Resources were $24/barrel In 1988 dollars. Higher costs were assessed by AAPG at $50tbarrel in 1986 dollars; higher costs assumed by ICF Resources were at $40Jbarrel In 1988 dollars. concludes indicated reserves, infested reserves, and mobile arid immobile oil recovery. SOURCE: AAPG (1989a); Kuuskraa et al. (1989~. estimated by AAPG are, however, generally consistent with the estimates announced in 1989 by the USGS and the MMS. Both the AAPG and the ICF estimates show the strong need for ad- vanced technology to convert the remaining resource base to producible reserves. At moderate cost the volume of resources, exclusive of proved reserves, essentially can be doubled with advanced technology and effi- ciency. ICF Resources shows an even greater volume of the resource acces- sible at moderate costs with advanced technology than with high costs alone.
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CONVENTIONAL PETROLEUM 27 In short, while early U.S. exploration and development could rely on econo- mies of scale, exploiting the remaining resources will generally require economies based on improved efficiencies. Both AAPG and ICF Resources estimate resources exploitable at moder- ate cost that are equivalent to three to five decades of current U.S. domestic production rates. At high costs and with advanced technologies, the ex- ploitable resources are obviously greater. Gas Resources Estimates of remaining U.S. natural gas resources are regularly made by an industry-based group, the Potential Gas Committee (PGC), and by the DOI (USGS for on land and MMS for offshore; see U.S. DOI, 1989~. The most recent comprehensive estimate of the entire natural gas resource base was made by a panel of gas analysts for the DOE in 1988. That panel consisted of representatives from industry, private foundations, state and federal governments, academia, and the estimating agencies and groups. The panel estimated that the volume of natural gas recoverable with exist- ing technology was 1059 Tcf for the continental United States. The panel further reported, by different categories of the resource base, volumes of natural gas that could be exploited at wellhead prices up to $3.00/Mcf and up to $5.00/Mcf (in 1986 dollars) (Table 2-2~. While adopting the DOE es- timates for existing technology, the AAPG has estimated the volumes of the total resource base exploitable at the above price levels including assump- tions of advanced technology. AAPG's estimated volume is equivalent to an 80-year natural gas supply at the current rate of consumption. ICF Resources, in a report to this committee, made separate estimates for gas accessibility (Table 2-2~. With existing technology, ICF Resources estimates volumes that are only marginally higher than the DOE estimates, based largely on reevaluation of potential from nonconventional sources. However, with advanced technology their estimates of moderate-cost natu- ral gas (up to $3/Mcf) from nonconventional sources substantially exceed AAPG estimates; at prices up to $5/Mcf, ICF estimates of some categories of resources are below those of AAPG. Natural Gas Liquids Assuming future yields of liquids from conventional natural gas on the order of those historically extracted, remaining volumes of natural gas liq- uids are estimated to range from about 12 billion bbl at moderate costs to about 20 billion bbl at gas wellhead prices up to $5.00/Mcf. These volumes constitute additions to the liquids potential from remaining crude oil re-
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28 FUELS TO DRIVE OUR FUTURE TABLE 2-2 U.S. Natural Gas Resources at Year End 1986 (trillion cubic feeds Existing Technology and Efficiencvb <$3.00/Mcf <$5.00/Mcf Advanced Technology and EfficiencyC <$3.00/Mcf <$5.00/Mcf Proved reserves 166 (162) 166 (187) 166 (163) 179 (187) Reserve growthd 197 (197) 226 (226) 313(N/A) 483 (N/A) Undiscovered 144 (144) 233 (233) 202 (N/A) 338(N/A) Low permeability 70 (79) 119 (86) 130 (245) 300 (275) Coalbed methane 8 (13) 12 (26) 40 (51) 90 (65) Shale 10 (17) 15 (20) 30 (37) 40 (46) Total 595 (612) 771 (778) 881 1430 aNumbers in parentheses are from ICE Resources (Kuuskraa et al., 1989~. Note: Mcf = thousand cubic feet. bDOE ~ 1986 dollars). CAAPG (1986 dollars). dIncludes inferred reserves, new pool, and reserve growth from gas aIld gas-asso- ciated oil reservoirs. SOURCE: Kuuskraa et al. (1989~; AAPG (1989b). sources. These estimates may be optimistic because the gas from deeper and unconventional sources is not as rich in liquids. PRODUCTION TECHNOLOGIES AND PROCESSES Primary oil recovery depends on the natural energy contained in the reservoir to drive the oil through the complex pore network to producing wells. The driving energy may come from liquid expansion and evolution of gas dissolved in the oil as reservoir pressure is lowered during produc- tion, expansion of free gas in a gas "cap," influx of natural water from an aquifer, or combinations of these effects. The recovery efficiency for pri- mary production is generally low when liquid expansion and solution gas evolution are the driving mechanisms. Higher recoveries are associated with reservoirs having water or gas cap drives and from reservoirs where gravity effectively promotes drainage of the oil from the pores. Eventually, the natural drive energy is dissipated. When this occurs, energy must be supplied to the reservoir to produce additional oil. Secondary oil recovery involves introducing energy into a reservoir by injecting gas or water under pressure. The injected fluids maintain reser- voir pressure and displace a portion of the remaining crude oil to produc-
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CONVENTIONAL PETROLEUM 29 tion wells. Waterflooding is the principal secondary recovery method and currently accounts for almost half of the U.S. daily oil production. Limited use is made of gas injection because of the gas's value; however, when gravity drainage is effective, pressure maintenance by gas injection can be very efficient. Certain reservoir systems, such as those with very viscous oils and low permeability or geologically complex reservoirs, respond poorly to conventional secondary recovery techniques. In these reservoirs im- proved geologic understanding and use of enhanced oil recovery (EOR) operations should be employed as early as possible. Conventional primary and secondary recovery processes, at existing lev- els of field development, will ultimately produce about one-third of the original oil in place (OOIP) in discovered reservoirs. For individual reser- voirs the recoveries range from the extremes of less than 5 percent to as much as 80 percent of the OOIP. The range chiefly reflects the degree of reservoir complexity or heterogeneity. The more complex the reservoir, the lower the achievable recovery. Of the remaining two-thirds of OOIP in domestic reservoirs (about 340 billion bbl), approximately 30 percent exists as conventionally moveable oil. A portion of this oil can be recovered through advanced secondary recovery techniques involving improved sweep efficiency in poorly swept zones of the reservoirs. For these reservoirs, well placement and comple- tion techniques need to be pursued consistent with the degree of reservoir heterogeneity. Such improved secondary oil recovery can be accomplished using advanced geologic models of complex reservoirs. The balance of the remaining two-thirds of unrecovered oil is oil that is or will be residual to efficient sweep by secondary recovery processes. Portions of this residual oil can be recovered by tertiary or EOR. The intent of EOR is to increase ultimate oil production beyond that achieved by primary and secondary methods by increasing the volume of rock contacted by the injected fluids (improving the sweep efficiency), reducing the resid- ual oil remaining in the "swept" zones (increasing the displacement effi- ciency), or by reducing the viscosity of thick oils. Current EOR technology processes can be broadly grouped into three categories: thermal, miscible, and chemical methods. These processes differ considerably in complexity, the physical mechanisms responsible for oil recovery, and maturity of the technology derived from field applica- tions. Although enhanced oil recovery methods using microorganisms or electrical heating have been proposed, their current state of development is still at the research and initial field pilot stage. Thermal recovery methods include cyclic steam injection, steamflooding, and in situ combustion. The thermal methods are used to reduce the oil's viscosity and provide pressure so that the oil will flow more easily to the production wells. The steam processes are the most advanced EOR meth-
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30 FUELS TO DRIVE OUR FUTURE oafs in terms of field experience. As a result they have the most certainty in estimating performance, provided that a good reservoir description is avail- able. Steam processes are most often applied in reservoirs containing vis- cous oils and tars. This is usually done in place of, rather than following, primary or secondary methods. Steam processes have been commercially applied since the early 1960s. In situ combustion, an alternate thermal process, has been field tested under a wide variety of reservoir conditions, but few projects have proved economic and advanced to commercial scale. When oil prices are right, it will probably be applied to moderate-size projects where it is not feasible to use other processes. Miscible methods use carbon dioxide, nitrogen, or hydrocarbons as mis- cible solvents to flood the reservoir and can produce 10 to 15 percent of the OOIP. The solvents mix with the oil without an interface and are very effective in displacing the oil from the reservoir. Unfortunately, they do not always achieve a high sweep efficiency. Their greatest potential is enhancing the recovery of low-viscosity oils. Commercial hydrocarbon miscible floods have been operated since the 1950s. Carbon dioxide mis- cible flooding on a large scale is relatively recent and could make a sub- stantial contribution to FOR production, if prices are right. Only limited field experience with nitrogen is available, but it may be attractive in areas without a ready supply of carbon dioxide and where the reservoir is deep enough to achieve miscibility. The chemical methods include polymer flooding, surfactant (micellar/ polymer, microemulsion) flooding, and alkaline flooding processes. These methods take advantage of physical attributes of chemicals injected along with a displacing water driver to improve recovery. Polymer flooding is conceptually simple and inexpensive, but it produces only small amounts of incremental oil. It improves waterflooding by using polymers to thicken the water to increase its viscosity to near that of the reservoir oil so that displacement is more uniform and a greater portion of the reservoir is con- tacted. Surfactant flooding is complex and requires detailed laboratory testing to support field project design, but it can produce as much as 50 to 60 percent of residual oil. Surfactants are injected into the reservoir to reduce the interracial tension between the residual oil and flood water to "wash" the oil from the reservoir rock. The surfactant causes the oil droplets to coa- lesce into an "oil bank" that can be pushed to production wells. Improve- ments in displacement efficiency clearly have been shown; however, sweep efficiency is a serious issue in applying this method. As demonstrated by field tests, it has the potential to improve the recovery of low- to moderate- viscosity oils. Surfactant flooding is expensive and has been used in few large-scale projects. As a result it is among the least developed of the FOR technologies.
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CONVENTIONAL PETROLEUM 31 Alkaline flooding is appropriate only for reservoirs containing specific types of crude oils. Surfactants are generated in the reservoir (rather than at the surface) by chemical reactions between injected alkaline chemicals and certain petroleum acids that must be present in the crude oil. Alkaline flooding, although lower in cost and simpler in concept than surfactant flooding, is not well developed. It has been tried only in a few reservoirs and requires considerable development. UPSTREAM OIL AND GAS ENVIRONMENTAL IMPACTS Upstream environmental impacts occur in the following activities: proration, production, and transportation. It is important that activities oc- cur with the least environmental impact that is realistically possible. Only a brief summary of these impacts is provided in this section. Exploration activities typically involve a variety of superficial surface studies plus shooting a seismic survey. Offshore seismic surveys involve essentially no impact. Land surveys can involve minor disruption of small plants but barely affects animals or structures. Offshore exploration wells are usually drilled from drill ships and have little impact. Land drilling requires clearing roughly 1 acre for rig operations. Drilling mud disposal techniques are well established and not considered hazardous when con- ducted properly. Blowout accidents are rare, so spillage, explosions, and other related concerns are infrequent. Air pollution is usually negligible. Typically, production activities involve clearing a drillsite, laying gath- ering pipelines, and constructing a small processing plant and storage tanks for each lease or unit. Drilling mud and process plant waste disposal are readily manageable and generally considered to have minor impact. When oil and gas are brought to the surface, produced water often accompanies them. It is separated and reinfected into rock at intervals where it either aids production or has no impact on the surface. The wells are carefully cased to avoid affecting other subsurface waters. After a drill rig is re- moved from a wellsite, the site is restored to original use and only some valves and pipes are visible. Processing plants and tankage are also visible but are relatively small compared to the size of an oil or gas field. Emis- sions to the air are usually tightly controlled and normally minimal. Acci- dents are always possible and spills of varying sizes can happen, but good . . . . . Operating procec ures minimize sue n miss naps. All these activities, either by small or large operators, could have envi- ronmental problems associated with them if proper methods and procedures are not followed. However, given correct practices, the probability of per- manent environmental damage is small. Transportation by pipeline, truck, tanker, or barge is uneventful under normal conditions. However, the recent Exxon Valdez tanker spill, and the
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32 FUELS TO DRIVE OUR FUTURE triple accidents the weekend of June 23, 1989, illustrate that accidents that can dispoil waterways and shorelines are possible. Such severe accidents have serious impacts, and efforts must be made to minimize their likeli- hood. TIME AND INVESTMENT REQUIRED FOR INCREASED OIL AND GAS PRODUCTION The time and investment required to bring large amounts of new domes- tic oil and gas to market are measured in the 5- to 10-year and billion dollar range. Smaller production can be managed on smaller time and investment scales. In this regard new domestic oil and gas production is different from facilities for conversion of nonpetroleum resources into liquid fuels; new oil and gas can quickly be brought to market in small increments at modest costs, while coal and oil shale conversion plants require large multibillion dollar grass-roots plants that do not produce until they are brought into operation a decade or more after planning begins. To understand the time and investment involved to produce new oil and gas, it is instructive to break the process into the basic steps required. For simplicity the following are defined: 1. Playlprospect development consists of those activities required to de- velop an active exploration interest in a new area. Such activities take 1 to 3 years and may require investments of hundreds of thousands of dollars or more. 2. Leasing is that activity required to obtain the right to drill and, if suc- cessful, to produce in the area of interest. Normally this takes a few months but can extend to several years in environmentally sensitive areas. Costs can range from tens of thousands to hundreds of millions of dollars depend- ing on the potential target, its apparent attractiveness, and competition for the leases. 3. Exploratory drilling results in the first well or wells to determine if hydrocarbons are present. It can take months and cost hundreds of thou- sands to millions of dollars depending on circumstances. 4. Delineation drilling results in subsequent wells aimed at determining the size and character of the deposit. Times and costs are similar to those of exploratory drilling. 5. Early planning, development drilling, facility construction and initial sales are those activities required to prepare an Environmental Impact State- ment, obtain permits, procure supplies, establish flow, and process and de- liver the fluids to an appropriate market. This may require several months to years to accomplish depending on the physical environment. Costs are millions of dollars per 1000 bbls per day of production. 6. Field development for primary and secondary production results in refinement of the understanding of the field geology and creation of a reser-
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CONVENTIONAL PETROLEUM 33 voir management plan to guide subsequent drilling, waterflooding, and even- tually EOR, if appropriate. Once development has begun, field extensions, infill drilling, waterflood- ing, and EOR generally evolve sequentially. The determinants of action and timing are oil and gas price outlook; reservoir character (amount of remaining hydrocarbons, geological complexity, etc.~; and availability of capital and technical personnel. Time and investment required here depend on specific circumstances. For our purposes it can be considered incremen- tally continuous, until economic incentive dwindles. Ranges for the pro- duction of increments from existing fields of 1000 bbVday of oil are on the order of months and millions of dollars. Extended reserve growth only requires additional refinement of the reser- voir geologic and engineering models through geoscientific and reservoir engineering study, since leases are secured and the presence of hydrocar- bons has been confirmed. This is followed by targeted infill drilling with iterative improvement of the models to more completely characterize reser- voir heterogeneities and identify hydraulic compartments. This should re- sult in subsequent modification of the planned programs. Since this has not been done on a routine basis, only limited experience is available on the cost and time for target infill drilling programs, but it is apparent that time and investments are relatively modest. Such programs might even be con- sidered a reasonable preliminary stage for implementing an EOR project. For EOR projects a pilot test is usually required, followed by full field implementation. Depending on the process and the field, preparation for a pilot can take a few to many years and cost on the order of $10 million. Full-field EOR implementation can take 5 to 10 years and millions of dol- lars per 1000 bbl/day of oil production. It is essential to note that U.S. industry no longer has the incentive or the ability to aggressively explore and develop new oil and gas resources or to implement EOR on a massive scale. This is because the twin oil price collapses of 1986 and 1988 decimated the domestic industry. Therefore, should the national need develop, a massive scale-up of domestic oil and gas development would probably take 7 to 10 years to accomplish. This estimate is based on the experience following the 1970 oil crisis, when it took about 6 years to double the U.S. oil drilling rig count (see Figure 2-2~. LOSS OF RESERVE GROWTH AND EOR POTENTIAL As oil fields are depleted, their production rates decrease send operating and maintenance costs escalate. At some point fields reach their economic limit, where a reasonable profit is no longer possible. Clearly, oil fields will reach this point sooner when oil prices are lower, as has been the case in recent years.
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34 4.5 to x 35 - - v ~ 25 o FUELS TO DRIVE OUR FUTURE ,. ~6 years to double ~ Arab on ~~/~/ 1.5 - embargo begins`_/ ~/1 0.5 1 4S30 1 A' Oil prices_ _ A start to fall ~ _/ I / |Saudis step up / \oll production \~1 Shah of Iran 8 ~ 4 deposed previous postwar low ~ \ 663 Current postwar bw .. ...' ~ 1967 1969 1971 1973 1975 1977 1979 1981 1983 1985 FIGURE 2-2 U.S. rig count since 1967. When profitable operations are no longer possible, wells are plugged with cement, equipment is removed, surface areas are returned to their preproduction condition, leases are relinquished, and operators abandon the field. Left behind in the reservoir is residual oil that in many cases could be recovered by infill drilling or EOR that is not instituted because econom- ics are unattractive at projected oil prices. Each year large numbers of oil fields are abandoned (the rate is the highest in the history of the industry) and their target oil is lost for decades, if not forever. This is because the well and equipment investments, the leases, and usually the understanding of the reservoir are lost. Releasing is usually time-consuming and very expensive, if not effectively impossible. It may be impossible because in mature producing areas the mineral interest owners have proliferated over the years, and developing reasonable con- tracts (mineral leases) is too complex and time-consuming. Under most situations, moving back into an abandoned reservoir will add $4 to A/ barrel to the cost of the additionally recoverable oil. When this is added to the incremental costs of redevelopment or EOR, it can make the costs pro- hibitive. The United States is thus losing potential target oil, mobile unswept, and other oil that could be recovered by EOR at a significant rate. Without higher oil prices or some government action, this potential source of U.S. Oil production will be postponed for a long time if not lost forever.
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CONVENTIONAL PETROLEUM 35 TECHNOLOGICAL OPPORTUNITIES At the committee's June 1989 workshop (see Appendix B), five experts made presentations on various EOR technologies. Their presentations cov- ered the three dominant process technologies, advanced geoscientific mod- els, and an overview of the status of EOR. Their presentations can be summarized as identifying eight opportunity areas. 1. Advanced geological reservoir modeling for complex reservoir sys- tems. Although petroleum has been exploited for decades, detailed under- standing of the influence of reservoir flow units and fundamental rock-fluid interactions in complex media is still at a relatively elementary stage. As a result field applications of secondary and tertiary processes often do not perform as expected. The cause of this deviation is often incomplete under- standing of the reservoirs). Recovery, both secondary and EOR, would be greatly improved if advanced geological-reservoir engineering models of the reservoirs could be developed. Improved reservoir characterization would lead to better predictions of where and how remaining oil is distributed, and better methods (using geostatistical techniques along with in situ imaging methods) to characterize heterogeneity at the macroscale and on a scale important for process predictions and would develop understanding and methods for scaling up reservoir description details to the scale of reservoir simulator grid blocks. Targeted infill wells and strategic completions would assure that all hydraulic flow units in a reservoir are contacted and swept. Advanced geological modeling is the essential key to enlarge mobile oil reserve growth. 2. Extraction technology for immobile oil. (a) Advanced miscible flood- ing methods have been extensively tested and shown to be effective in well- understood reservoirs. The technology can be characterized as a midlife technology. Current industrial research is primarily focused on optimizing existing technology, with some effort on developing new processes, primar- ily foams for improving sweep efficiency. Opportunities for future research include improved reserve* characterization; improved process prediction to include quantitative mechanistic descriptions of fingering (unstable intru- sion of the displacing fluid into the reservoir oil) and displacement effi- ciency; more quantitative understanding of heterogeneity effects on mis- cible processes and the degree of heterogeneity definition required; im- proved simulation approaches and procedures with innovative computing techniques; and"new" ideas. (b) Chemical processes may be viewed as dramatic extensions to water- flooding, the most common secondary recovery method. Chemicals are added to the drive water to improve sweep or displacement efficiency. Four
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36 FUELS TO DRIVE OUR Fl)TURE types of chemical recovery processes can be identified. Permeability modi- fication and profile control uses chemicals to remedy poor sweep efficiency caused by vertical permeability stratification. Several commercial systems are available, and several field tests have been performed. The results are mixed but promising. Predictability is poor. Opportunities for research include improved mathematical models to guide application and process development and development of systems capable of extending treatment away from the well bore deep into the reservoir. Polymer flooding uses polymers to thicken the drive water so that its vis- cosity is close to that of the reservoir oil. The process is understood and can be simulated if the reservoir description and rock-fluid interaction prop- erties are known. There is difficulty in propagating the polymer over long distances in the reservoir. The major research opportunities are developing new polymer structures that tolerate high reservoir temperatures, that can move long distances in the reservoir without degradation, and that can be injected at rates higher than those currently used. Surfactant flooding uses chemicals to improve the displacement effi- ciency by mobilizing residual oil. The process is understood, and design procedures have been developed. Effective surfactant systems have been developed for moderate-temperature sandstone reservoirs that have rela- tively low salinity water. Achieving good volumetric sweep is a major concern. Research opportunities include improved surfactants for more hostile reservoir environments and methods to improve volumetric sweep and improved process performance through reservoir characterization. Alkaline polymer flooding uses the mechanism of in situ formation of surfactants by neutralizing petroleum acids. The process is not well under- stood, and there have been few successful field tests. The process is only suited to specific reservoirs. Opportunities for research include defining the process mechanisms, developing predictability, and field testing to con- firm understanding and demonstrate oil mobilization. (c) Thermal methods are commercially proven processes for enhancing the recovery of heavy oils by reducing their viscosity. Three methods are currently used. Steam stimulation uses a single well for injection, "soak," and subsequent production. It is relatively inexpensive and has rapid re- sponse. It results in low ultimate recovery, lost production during "soak" periods, and limited well life and has poor predictability. Opportunities for research include process improvements to increase recovery, improvements in sand control and well materials to improve well life, and greater under- standing of the process in order to improve predictability. Steam flooding extends the thermal benefits of steam to greater portions of the reservoir by using separate wells for injection and production. It increases the recovery by increasing the reservoir volume affected by the steam. It also extends the applicability of the method to light oil reservoirs. It suffers from poor
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CONVENTIONAL PETROLEUM 37 sweep efficiency due to steam override and is expensive because of high operating (fuel) costs. In general, predictability is good. Research opportu- nities include developing methods for improving sweep efficiency both ver- tically and horizontally. In situ combustion uses injected air to oxidize part of the oil to raise the temperature of the reservoir. It can extend applicability of thermal methods to thin reservoirs and to greater depths. Unfortunately, the process is diffi- cult to control, has poor vertical sweep, and is expensive, and part of the oil is consumed as fuel. Research opportunities include improving process control, developing methods for improving sweep efficiency, and reducing capital costs. Generally, all of the thermal methods could use techniques for improving sweep efficiency and process control improvements or mate- rial improvements to reduce heat losses or the costs of heat generation. (d) Advanced EOR methods. Research on several other EOR methods is under way. These include, but are not limited to, microbial methods and electric heating of the reservoir. These methods provide alternative tech- niques for achieving the EOR mechanisms, such as reduction in oil viscos- ity or improvements in displacement or sweep efficiency. Since they are novel, it is difficult to predict whether they will be able to do this in a cost- effective manner. Currently most research is directed toward understanding the mechanisms, with limited field testing under way. 3. Advanced monitoring. All recovery processes primary, secondary, and tertiary are difficult to monitor. The processes occur away from the well bore, and no techniques are currently available for monitoring their performance at these remote locations. Geophysical methods that could measure properties that allow inferences to be made about the performance of the process would greatly assist control and allow early remedial action to be taken. 4. More effective production technology. All production processes re- quire effective well completions. Horizontal drilling offers the opportunity to change the geometry of reservoir flow and increases the contact area between the well bore and the reservoir. Research to determine the influ- ence of well completions on process performance and to develop cost-effec- tive improvements can lead to potential opportunities. 5. Improved exploration techniques. Much of the remaining undiscov- ered U.S. oil and gas resources, particularly on land in the lower 48 states, will be discovered and exploited in small to moderate-size increments. While exploration technology development is highly competitive and proprietary, fundamental research aimed at supporting the development of cost-effective exploration methods for such targets should be a part of DOE's research program. Included could be fundamental geophysical, geological, and geochemical studies. Close coordination with industry in such matters will help ensure maximum benefits and avoid conflicts with proprietary interests.
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38 Fuels TO DRIVE OUR FUTURE 6. Technology Granter. Technology transfer is not a research area but is an essential area to note, particularly for the very important independent producer. In the past, technology was naturally transferred from majors to independents by personnel migration and dissemination from the major companies. This was effective because both independents and majors oper- ated in the same geographic areas. With major producers shifting their investments into frontier areas and international operations, it can be ex- pected that their research will focus more on these areas. There is a sub- stantial body of available technology that independents could use to their benefit if it were available to them. However, it is unlikely, given the lack of technological sophistication and low capitalization of independents, that this technology will be exploited by them in the normal course of events. Thus, a public sector program of technology transfer could help assure that unrecovered domestic oil resources are conserved and efficiently devel- oped. The development of such a program is an important challenge to the government, but was not considered in any detail in this study. DOE RESEARCH PROGRAM With the exception of exploration methods, DOE currently supports some research in all of the areas of oil and gas research where this committee sees technological opportunities. From a survey by the National Petroleum Council ~PC), corporate research likewise addresses these areas to varying degrees (NPC, 1988~. However, the total expenditure, in oil and gas recov- ery research, public and private, is small relative to the value of oil and gas produced or to the value of oil and gas reserves added through improved recovery. According to the NPC report, industry expenditures for recovery research on reservoir characterization and FOR processs technology im- provement averaged about $195 million yearly for the first half of the 1980s. (The Energy Information Administration indicates much larger expendi- tures, i.e., $645 to $801 million per year in the mid-8Os, but their category of oil and gas recovery is broader and includes all upstream R&D activity [EIA, 1987a]~. Public federal and state expenditures for such research is on the order of $40 million annually. The current DOE expenditures of about $24 million per year for enhanced oil recovery are substantially less than for DOE's expenditure of about $86 million per year for other liquid fuels (this does not count the large budget for other uses of coal). Considering the contribution of domestic oil and gas to U.S. supply and the potential of these resources to add quickly to future supplies, public research efforts should be brought into balance with expenditures for other resources, and sufficient incentives should be provided to enlarge corporate research on domestic oil and gas recovery.
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CONVENTIONAL PETROLEUM 39 SUMMARY This chapter has shown that in the price range of $25 to $50/barrel for oil, advanced oil recovery technologies could permit the United States to maintain a significant level of domestic oil production for several decades. This would allow time for R&D on converting nonpetroleum resources into liquid fuels. The next chapter addresses the economics of various conver- sion technologies producing liquid transportation fuels from heavy oil, tar sands, natural gas, and nonpetroleum resources.
Representative terms from entire chapter: