EOR Projects Research Articles

Case History and Appraisal of the Medicine Pole Hills Unit Air-Injection Project

Summary The Medicine Pole Hills Unit (MPHU) EOR project is the deepest air-injection/in-situ-combustion project in the Williston basin. A unit comprising 9,600 acres with 13 producing wells was formed in July 1985, and air-injection operations began in Oct. 1987. Laboratory combustion tests and detailed feasibility studies were completed before starting the full scale project. The combination of light oil (39°API), carbonate formation, hot reservoir (230°F), and low permeability (1 to 30 md) makes this a unique air-injection project. Cumulative air injection as of Dec. 1993 was 12 Bscf. This paper reviews production performance of the MPHU to date. Oil production from the unit has shown a significant increase over its historical decline, and a processing plant has been installed to recover the liquids stripped from the oil by the produced flue gas. Although well workovers, acid fracturing, and pump changes in some producers complicate the determination of the oil response to air injection, production decline-curve analysis was used to estimate the incremental oil recovery due to air injection. The current air/oil ratio (AOR) is 8 Mscf/STB. Also discussed are the changes in air utilization over time, the benefits of the liquids recovery from the produced-gas stream in such a light-oil project, and an estimate of the field burned volume.

Analytical Software For Pool-wide Performance Prediction of EOR Processes

Abstract In order to facilitate management of large scale gas miscible EOR projects, a software package called FAME (Forecast Analyser for Miscible EOR) has been developed based on an analytical approach. The primary role of the software is to provide pool-wide performance predictions from mechanistic displacement characteristics determined either by part-pattern numerical simulations, Of by preliminary history matching of field data. The notable features incorporated into the software are that:important flood parameters, such as pattern allocation factors, solvent distribution and sweep, are dependent on pool-wide fluid movement and pattern interactions, which in turn are dependent on the injection/production sequence of historical and planned flood operations,crucial physical mechanisms associated with the gas miscible EOR, such as gravity override, solvent and chase gas miscibility with reservoir oil, and miscible and immiscible displacement processes are adequately represented, andresults of mechanistic numerical simulations or history-matching past field data can be mimicked through variations of a small number of parameters. The software has impacted the management of the Judy Creek hydrocarbon miscible projects with the achievement of a successful history match and the provision of useful information related to flood performance. Introduction During the operation of large-scale oil recovery projects, especially in enhanced oil recovery projects such as hydrocarbon miscible floods, it is highly desirable to be able to assess the project performance. Factors of interest include pool-wide fluid movements, local fluid distribution, sweep efficiency and displacement characteristics, as well as the prediction of future performance under different operating scenarios. Numerical simulation is a powerful method to assess the compound effects of numerous crucial mechanisms involved in various enhanced oil recovery processes. However, numerical simulation models for enhanced oil recovery processes require a large number of simulation grid blocks and small rime steps in order to adequately represent the critical mechanisms. A typical example of such a mechanism is the gravity override of injected solvent in gas miscible processes which causes low sweep efficiencies of solvent as described by H. Stone(1). The solid curve in Figure 1 is the theoretical relationship between the vertical sweep efficiency and water to solvent injection ratio (WAG ratio) at the fixed total fluid rate based on the Jenkins' analytical Expression(2) derived from the Stone's vertical conformance theory. The triangles and circles are corresponding outputs of the Todd-Longstaff type numerical simulations(3) using the horizontal and vertical numbers of grids of 10 × 3 and 15 × 13, respectively. In these numerical simulations, the sweep efficiencies were determined from values of tertiary oil recovery normalized by the tertiary oil potential at the two pore volumes of solvent injection. It is apparent in Figure 1 that the number of grids of 10 × 3 is not enough and overestimating the sweep efficiency, whereas the 15 × 13 is sufficient for representing the mechanism of gravity override. In three-dimensional models, several thousand grid blocks typically are necessary for part-pattern (such as a quarter five-spot pattern) simulations, even with a uniform geology description.

Adsorption of Foam-forming Surfactants In Berea Sandstone

Abstract Adsorption measurements carried out with representatives of four classes of surfactant suitable for foam flooding (alpha olefin sulphonate, internal olefin sulphonate, linear xylene sulphonate, and betaine) on Berea sandstone at different conditions of temperature and salinity are described. Adsorption of (he anionic surfactants from a low salinity brine is low, but increases substantially at moderate salinities. Limited solubility of the anionic surfactant in aqueous media tends to drive these surfactants to the solid/liquid interface and can also lead to increased surfactant loss through precipitation. The betaine is highly soluble, but adsorbs very strongly on sandstone. Adsorption of this surfactant can be reduced by mixing it with an anionic surfactant. Introduction EOR production in North America is dominated heavily by gas or vapor flooding. Out of total of 371 EOR projects, 294 involve injection of steam CO2 or hydrocarbon solvent(1). Became of the low density and viscosity of the injected fluid, gas and vapor flooding processes tend to suffer from poor sweep efficiency. This problem may be alleviated through the use of mobility control foams(2,3). While the mechanism of lamella generation and collapse is crucial to foam performance and propagation, the maximum distance that a foam will travel is dictated by surfactant loses in the reservoir, caused by adsorption at the solid/liquid interface, precipitation, chemical degradation, and partitioning into an immobile oil phase. This paper deals with the last and frequently most important of these mechanisms. Surfactant classes most commonly applied in laboratory studies of EOR-foams and in field applications include alkyl aromatic sulphonates and olefin sulphonates. Since much of the EOR-foam literature deals with steam foams, surfactant selection has often been determined by the requirement of chemical stability at steam flood temperatures. The following ranking has been assigned to several surfactant classe in terms of their thermal stability(4) alkyl aryl sulphonates > olefin sulphonates > petroleum sulphonates > ethoxylated alcohols and ethoxylated sulphates. The surfactants that have been found the most thermally stable are also the most likely to precipitate in the presence of inorganic electrolyte. Surfactant solubility has been found to decrease in the following order(4); ethoxylated alcohols or sulphates > olefin sulphonates > petroleum sulphonates = alkyl aryl sulphonates. A characteristic of the surfactants most commonly described in connection with EOR-foams is thus their limited solubility in brines. The high molecular weight surfactant homologues suitable for steam-foams have very limited solubility in aqueous media and are expected to have a higher affinity for the solid/liquid interface than lower molecular weight homologues. Steam flood temperatures will favour low adsorption levels and increased solubility. During steam flooding, a surfactant encounters salinity and temperature gradients and a knowledge of the dependence of surfactant behavior on both parameters is required. Surfactants suitable for the extreme conditions of salinity and hardness encountered in many Alberta reservoirs have been identified(5). Detailed measurements of the adsorption properties of these surfactants have been previously described(6–8). By contrast, reported adsorption data for surfactant classes commonly used for steam flood applications are rather limited(9–15).

A Practical Artificial Intelligence Application in EOR Projects

Summary Two knowledge-based expert systems and a FORTRAN computer program were developed to aid the reservoir engineer in selecting appropriate EOR method(s), determining the quantity(ies) of recoverable oil, and evaluating economic feasibility of the selected method(s) for candidate reservoirs. Testing and sensitivity analyses showed that the developed expert systems are reliable and consistent with human experts' opinions. The expert systems were designed to accommodate new knowledge and technology that may emerge and become available in the future.

Applications of Oxygen Activation for Injection and Production Profiling in the Kuparuk River Field

Summary A new time-dependent method of oxygen-activation logging, now being used in the Kuparuk River field on the North Slope of Alaska, provides critical data for waterflood performance evaluation, assessment of ultimate recovery, and evaluation of potential for infill drilling and EOR projects without the use of radioactive tracer materials.

Applications of Economic Analysis in EOR Research

Summary Enhanced recovery ha been a subject of interest for the last 30 years. The oil-price shocks of the 1970's generated research and field tests on a wide variety of EOR methods with various levels of success. With lower oil prices and less favorable price forecasts for the coming years, interest in EOR waned. Yet the logic behind EOR - to improve substantially recovery from the present resource base - has not changed. Thus, EOR is still essential in the long run. However, EOR projects must prove themselves economical under much more stringent criteria than previously. This paper demonstrates how economic analysis on currently uneconomical EOR processes can be used to determine the most effective direction for research. Economic analysis can help determine (1) whether fundamental technical limitations preclude development of a practical process, (2) the features of the process to which the process economics are most sensitive, and (3) the influence of timing on process economics. By defining the most crucial questions, we can focus the research effort and maximize the probability of success. Introduction One of the first steps in planning EOR research usually is the application of a set of technical screening parameters, developed to provide general guidelines for the applicability of a given process to a given oil accumulation or to an inventory of fields with known general characteristics. For example, if a large fraction of a company's oil in place (OIP) is light oil in sandstone reservoirs, surfactant or miscible flooding might be considered in these EOR prospects. If the company's resource base is largely in heavy oils and tar sands, thermal methods might be identified as appropriate. These technical screens, however, should not replace an economic screen early in the research effort. Research performed solely on the basis of a technical screen may result in a process that can recover a large fraction of the OIP under laboratory conditions but that has an intrinsic cost that exceeds the current oil price when applications are considered. The net result of the research is then a report indicating the potential reserves recoverable if the oil price (ever) reaches a given benchmark level. While such a result may be of interest on a global perspective, it will not add reserves to the company base. On the other hand, if an economic screen is carried out, crucial parameters, both technical and economic, may be identified before a significant research commitment is made. To perform an economic screen, one develops a model of the selected EOR process and applies it (albeit in a simplistic form) to a model reservoir representative of the target accumulations. This model should include the reservoir engineering aspects of the process and such information as the EOR facilities necessary and proposed well patterns and spacing (and thus the capital expenditures required). With a more comprehensive model, the sensitivity of the project economics to a variety of parameters can be assessed better and the research effort focused more narrowly, It may become evident that the most critical parameter is not a technical one associated with the process but a capital or operating expense or an alternative method for increasing the reservoir's ultimate recovery. Two examples are considered to illustrate these points.

PC-Based Quick__Look Graphical Postprocessing in Reservoir Simulation for Thermal Recovery

Summary In reservoir management, use of numerical reservoir simulators is playing an increasing role in developing planning, completion design, operating policies, and surveillance. Computer models, both in-house and commercial, are being used in EOR projects with detailed reservoir description for better understanding of the physics of multiphase fluid flow through porous media, history matching field and/or well performance, performing case sensitivities for variations in operating policy, and optimizing pattern and well spacing. For reservoir simulation to reach its full potential, it must become a tool that practicing reservoir engineers use with a high level of confidence. The goal of this paper is to demonstrate graphical postprocessing of reservoir simulation output as a key part in the overall results analysis process and as a critical link in assisting reservoir engineers with limited simulation experience to make competent decisions regarding reservoir development and operation.

中国のＥＯＲの現状について

中国のＥＯＲの現状について

Influence of Geology on the Design and Maintenance of Steam-Assisted Thermal EOR Projects in the Southern San Joaquin Basin, California, USA

California, the fourth largest oil producing state and the largest steam assisted thermal EOR (SAT EOR) producing region in the United States, produced 350.7 MMBO in 1990. SAT EOR accounted for 180.8 MMBO (52%) of which 163.9 MMBO (91%) came from fields in the southern San Joaquin Valley. SAT EOR production began in California in 1960 and, over the past 30 years, geologic studies have proved crucial in all successful projects. Most project failures, either economic or technical, can be traced to a lack of adequate geologic input during either the initial design/implementation or subsequent reservoir management stages. Reservoirs range from structurally and/or stratigraphically simple to highly complex. Detailed geologic study is essential to define the external shape of a target reservoir for subsequent engineering design. Further study of internal details of the reservoir can anticipate potential clay or sanding problems, identify possible internal fluid barriers, and catalog other reservoir inhomogeneities. After initial project implementation, a second geologic review is recommended to incorporate new well data and modify the original interpretation. Once on-line, continuous monitoring of the target reservoir for temperature variation and fluid movements is essential to maintain peak efficiencies, time adjustments to steam injection rates, and fine-tune reservoirmore » performance. Although such reservoir management is primarily an engineering function, geologic input is critical to understanding internal reservoir inhomogeneities and barriers affecting fluid and heat movement. Case studies from Kern River, Midway-Sunset, and Cymric fields provide examples of how proper geologic studies can reduce capital investment, increase recovery efficiency, and maximize profitability.« less

Oil Recovery by Gravity Drainage Into Horizontal Wells Compared With Recovery From Vertical Wells

Summary Gravity drainage is a significant factor in many EOR projects, particularly those involving steam stimulation and extended recovery from depleted reservoirs. This paper compares the effect of dip, reservoir thickness, oil mobility, and well spacing on production from horizontal vs. vertical wells. Total production from vertical and horizontal wells as a function of time also is compared. The basic physical concept involved in this study is the constriction coefficient. For a horizontal well, the constriction coefficient is larger than that for a vertical well at the start of drainage but that difference decreases with time.

An Approach To Optimize Economics in a West Texas CO2 Flood

Summary EOR projects, notably CO2 floods, are the next generation of recovery methods in the more mature west Texas waterfloods. Installing and operating a CO2 flood can be extremely expensive. In this paper, we discuss methods used to make several active CO2 floods more profitable by reducing operating costs and deferring investments. Introduction Our goal in studying several active west Texas CO2 floods was to determine the optimum near-term cash flow, overall project economics (rate of return, present woth, etc.), and oil recoveries. We developed various CO2 flood designs with a reservoir simulator by altering specific operating parameters, including the half-cycle slug size, gas/water ratio (GWR), injection schemes, and total CO2 slug sizes. The resulting injection and production rates were then entered into an economic simulator to determine the most economical set of operating conditions. We also assessed the impact of various economic conditions - oil prices, CO2 prices, gas processing fees, and operating costs - on the optimization process. This was done to ensure that the optimum set of operating conditions did not change drastically should the economic environment change. This study shows how optimizing operations can significantly improve the economics of existing CO2 floods. An additional benefit of the study was insight gained on plant sizing and adjusting injection schemes to minimize or defer investments while maximizing the economics of new projects. Background During the late 1970's and early 1980's, Amoco Production Co. committed significant manpower to evaluate the feasibility of full-scale CO2 flooding in west Texas. Before the feasibility work, Amoco undertook numerous CO2 pilots in various fields.1 Because of high crude prices, optimistic price forecasts (Fig. 1), and successful pilot recoveries, the future of CO2 flooding looked promising. The approach taken at the time was first to history match waterflood performance with an in-house black-oil simulator.2 The resulting reservoir description then was transferred to a streamline generating model and finally to a miscible streamtube model. The CO2 prediction was done at a single GWR with the CO2 injection slug size changed to find an optimum based on present worth. The reservoir simulation provided oil, gas, and CO2 production rates and CO2 injection rates for input into an economic model. Because of the man-hours and computer time involved in simulating the CO2 process, only a few GWR's were tried, with slug size as the main variable. In these early CO2-flood designs, CO2 reinjection was planned and a plant design was needed to remove H2S and hydrocarbons and to handle the peak predicted total gas production. Because of the single GWR being used, the gas rate was expected to increase to some peak and then decline, leaving excess plant capacity. This type of injection scheme impaired the economics because a large plant investment was needed at the beginning of the project. Unless there was an offset property feasible for CO2 flooding, the excess plant capacity went unused once the peak was past. The costs of plants and other investments were relatively high compared with today's environment because of high oil prices and high inflation rates. Most projects were still economical, however, because oil price forecasts were optimistic and tax relief from the Windfall Profits Tax was granted for EOR projects. One shortcoming of this early approach was the optimistic nature of the miscible streamtube model. Although this model adequately handled loss of miscibility, it was unable to regain it should the pressure rise above the miscible pressure. The model also was too efficient in areal sweep: the displacement was piston-like through the streamtube and all streamtubes were eventually swept for nearly 100% areal sweep efficiency. Injectivity losses also were handled inadequately in the streamtube model. Water hysteresis was accounted for, but solvent relative permeability effects3,4 were not. The miscible streamtube model also had limited ability to make changes in the pattern configuration and injection schemes. If such changes were to be made, the streamline generator had to be run again for entry into the miscible streamtube model. This was both time-consuming and costly. As a result of these model shortcomings, many economic sensitivities were run with various rate and reserve scenarios to become comfortable with the final CO2-flood design.

IOR resource potential of Norwegian North Sea sandstone reservoirs

The potential for improved oil recovery by surfactant flooding and by water alternating gas injection (WAG) in Norwegian North Sea sandstone reservoirs has been evaluated. Fifteen fields containing various formations and reservoirs have been studied, some very roughly and some in more detail. Reservoir types that seem to be suitable for surfactant flooding or for WAG have been identified. The volume of remaining oil after waterflooding has been taken as a starting point in these fields to obtain a range for the potential increase in oil reserves. Other IOR-methods with a possible recovery potential are discussed briefly. Finally some attention is given to the timing of EOR projects from a national perspective.

The value of reservoir geophysics

Cutbacks are occurring in domestic exploration and US oil fields are maturing. Companies are now putting greater emphasis on improving the profitability of their existing assets through increased production and improved efficiency. This has led to a surge of interest in reservoir geophysics as new borehole methods are added to the existing toolbox of seismic techniques. Infill wells are no longer drilled on a regular grid step‐out pattern but are based on geophysical models of the structure and stratigraphy. Repeat surveys are also becoming an increasingly acceptable method of monitoring EOR projects.

Effect of Well Abandonments on EOR Potential

EOR holds significant potential for producing additional oil from known reservoirs in the U.S. However, the economical application of the tertiary processes require to produce this oil relies on the use of existing wells as points of reservoir access. Abandonment of these wells could substantially reduce the future recovery potential of the huge known remaining oil resource. This paper summarizes the effect of well abandonments on recovery potential by various EOR methods for more than 1,400 major fields that account for 67% of total known original oil in place (OOIP) in the U.S. The study concludes that replacing existing wells (after their abandonment) would significantly increase costs and reduce U.S. EOR reserves.

Thermal Oil Recovery With Horizontal Wells (includes associated papers 24403 and 24957 )

"A 2,000- to 4,000-ft-long horizontal wellcan replace several vertical wells, reducinginvestment and operational costs." Introduction Horizontal-well technology is now beingused in EOR projects, especially in thermaloil recovery. Although horizontal wells haverecently been used in miscible and water-floodprojects, the main EOR applications to dateare in steam projects. Several horizontalwells have been drilled as pilot projectsfor thermal oil recovery in bitumen andheavy-oil reservoirs. A few field pilotsshow commercial viability. Thermal oil recovery is used to produceheavy oil or bitumen in high-permeabilityreservoirs. The main advantages of the useof horizontal wells are improved sweep efficiency, enhanced producible reserves, increased steam injectivity, and a decrease inthe number of wells required for fielddevelopment. This last point is especiallyimportant in thermal oil recovery projects, where several closely spaced vertical wellsare required for economic development. A2,000- to 4,000-ft-long horizontal well canreplace several vertical wells, reducinginvestment and operational costs. The maindisadvantage of horizontal wells is theirinitial cost. Moreover, horizontal wells arecommonly completed in only one zone ata time, resulting in drainage of only onelayer. Horizontal wells have been completedin multiple zones, although not yet in thermaloil recovery applications. In bitumen reservoirs, attaining reasonableproduction rates without steaming is difficultbecause of the high oil viscosity. (Bitumenis oil with less than 10API gravity anda viscosity of more than 10,000 cp atreservoir conditions.) Steam injectivityalso can be a problem. Even with horizontalwells, initial steam cycling normally will benecessary to establish steam injectivity. Incontrast, in heavy-oil reservoirs, wells canbe produced at low rates even without steaminjection. (Heavy oil has a gravity of morethan 10API and a viscosity of less than10,000 cp at reservoir conditions.) Here, steam injection with horizontal wells isprimarily to enhance production rates, toimprove sweep efficiency, and to increaseultimate oil recovery. Injectors or Producers Horizontal wells can be used as injectors orproducers. The large contact area ofhorizontal wells can enhance injection ratesin injection wells and improve productionrates in producing wells. When horizontal wells are used as producers, they providea large producing capacity with highproduction rates. Hence, high steam injectionrates in surrounding injection wells arenecessary to maintain reservoir pressure. Whenhorizontal wells are used as injectors, theninjecting steam uniformly along the well length occasionally may be difficult, espeially during the initial steam-injection period. This is because steam condensation ina cold horizontal well reduces the welllength available for steam injection. Thisproblem can be reduced or eliminated bypreheating a long horizontal wellbore beforesteam injection. In field applications, excluding cyclicsteam stimulation, horizontal wells are usedmore often as producers than as injectors. In horizontal producers, at least initiallybefore the heat front arrives and the entire wellbore is heated, only cold heavy oil maybe produced. The pressure drop in the longwellbore can be significant because of thehigh viscosity of the cold oil, which maycause uneven production along the welllength. Recovery Process Concepts Horizontal wells provide flexibility indeveloping well patterns for enhancing theweep efficiency of thermal oil recovery. Itpossible to drill a long horizontal well, or to re-enter an existing vertical well and drill short drainholes 100 to 300 ft long)to enhance steam injectivity and/or oilproductivity. This procedure can beespeially useful in multilayered reservoirswhere a specific zone can be developed witha minimum number of vertical wells. In multilayered heavy-oil reservoirs, suchis those in South America, production insome zones is delayed because of theunavailability of producing wells. In thesemultilayered reservoirs, the number of wells required to drain several zonessimultaneously is too large. JPT P. 1302⁁

Methodology for the Specification of Solvent Blends for Miscible Enriched-Gas Drives

Summary Many Alberta EOR projects rely on injection of enriched natural gas to displace oil left by primary or secondary operations. An important practical design requirement in such projects is to specify the solvent—a blend of an expensive C2+ enriching stream (which varies in composition) and dry gas—to minimize the cost of the displacing fluid. This paper outlines the derivation with a new methodology of a C2+/dry-gas blending correlation for a large Alberta miscible flood. The blending correlation used data from rising-bubble apparatus (RBA) experiments, which allowed fast, precise determinations of solvent/oil miscibility. Before undertaking the derivation, the RBA test was shown to give the same results as the standard slim-tube experiment for the system studied. This correspondence was anticipated from previously developed theoretical concepts about the relevant mechanism of miscibility development. Proper description of the mechanism is crucial for correct interpretation of miscibility experiments. Equation of state (EOS) multiple-contact flash calculations and EOS-based compositional simulation of the displacement process were used to analyze miscibility development for this system. This conceptual understanding formed the basis for the use of the recently developed RBA technique to generate data for the blending correlation.

Reduced Adsorption And Separation Of Blended Surfactants On Sand And Clay

Abstract Recent successful field trials of foam floods using surfactants containing disulfonated alkyldiphenyloxides have stimulated interest in the use of these surfactant in other EOR projects. Adsorption and separation of such surfactants is still a concern among some members of the petroleum industry. This paper will briefly discuss some of the advantages of using blended surfactants, notably enhanced mobility control and improved hardness tolerance. The main emphasis will be on the adsorption and separation of these surfactants when in contact with sand and clay. It has been found that adsorption of surfactants from blends is significantly lower than from "pure" surfactants and that separation of the blends is much less of a concern than is commonly believed. Adsorption and separation studies were done using water containing different concentrations of inorganic salts, and sand and sand/montmorillonite adsorbents. Introduction Recent successes in Alberta oil fields, notably by Signalta Resources of Calgary and Dome/Amoco, also of Calgary, have stimulated interest in the use of blended surfactants for enhanced oil recovery by foam flood. There are several reasons for considering blended surfactants for EOR application. These include enhanced mobility control and improved solubility. Experiments carried out at the Petroleum Recovery Institute (PRI) in Calgary using high pressure core tests, and in the Oil and Gas Lab at Dow using low pressure equipment have indicated a synergistic effect in mobility control as a result of blending surfactants. These results were presented at the 7th International Symposium on Surfactants in Solution(1), held in Ottawa in October 1988. Alpha olefin sulfonates (AOS's) are relatively inexpensive and available, produce good foams and are thermally stable, all important considerations for a good foam flooding surfactant. The biggest impediment to the use of AOS's in enhanced oil recovery is the very poor solubility of these surfactants in water containing divalent captions such as calcium and magnesium. Many reservoirs contain enough of these metal ions to preclude the use of pure AOS. This obstacle can be overcome by blending AOS with another type of surfactant. There are some lingering concerns about the wisdom of using blends, primarily because of anticipated separation of the components of the blends as a result of preferential adsorption. Results Solubility One of the products which has been used in the field is a blend of AOS and DOWFAX* disulfonated alklydiphenyloxide (DPOS) produced by Dow Chemical. The structure of this disulfonate surfactant is shown in Figure l. Calcium and magnesium salts of these disulfonates are water soluble, and remain so even in very concentrated solutions of inorganic salts of these metals. The solubility of AOS in sodium chloride solutions is increased by the presence of the disulfonated diphenyloxide. The first set of results (Fig. 2) shows the effects of temperature and blend composition on the solubility of the surfactant in sodium chloride solution. The concentration of AOS was held constant at 1.0 g AOS (- 50% active) in 100 mL of water. Varying amounts of the diphenyloxide surfactant (- 50% active) were added to the AOS solutions to give AOS/DPOS weight/weight ratios as shown.

Economic Effects of Environmental Regulations on Finding and Developing Crude Oil in the U.S.

Summary A number of legislative and regulatory initiatives being considered toprotect the environment could affect the economics of U.S. oil and gas E and P. This paper summarizes the results of a comprehensive assessment of thepotential cumulative energy and economic impacts of some of these initiativeson U.S. crude oil supplies. The results of the analysis clearly demonstratethat increased environmental regulations on U.S. crude oil E and P cansignificantly affect ultimate crude oil recovery. The extent of regulationsimposed will determine the level of impact, but significant effects could befelt over a wide range of regulations, crude oil prices, and levels ofdevelopment of prices, and levels of development of extractiontechnologies. Introduction Not all environmental statutes require the U.S. Environmental Protection Agency (EPA) or other regulatory agencies to consider costs and/or energyeffects when establishing regulations. Even when such analyses are performed, they are often limited in scope; they generally consider only the impactsassociated with a specific regulation and almost always assume no effects fromregulations under other statutes. This paper summarizes the results of anassessment of the potential cumulative energy and economic impacts ofenvironmental initiatives on the U.S. crude oil supplies. This assessmentinvolved a review of selected environmental initiatives under the authority ofthe Resource Conservation and Recovery Act. the Safe Drinking Water Act, the Clean Water Act, and the Clean Air Act. The estimated incremental compliancecosts associated with each initiative were based on the practices likely to berequired to comply with the initiative. From a review of these initiatives, three composite regulatory scenarios were developed, representing low, medium, and high levels of incremental compliance costs. The regulatory initiativesconsidered under each scenario are organized by environmental statute andsummarized in Tables I through 4. The three sets of regulatory initiativesproposed in this analysis do not necessarily proposed in this analysis do notnecessarily represent any set of regulations recommended or supported by the EPA; any other federal or state agency, or any specific association, company, or institution. The scenarios proposed are intended to represent the range ofproposed are intended to represent the range of possible combinations ofregulations, used possible combinations of regulations, used only forestimating the impact of various intiatives on U.S. crude oil supplies. Theestimated unit compliance costs are based on analyses performed by the EPA andthe API. Future production from four categories of U.S. crude oil resources wasevaluated:continued conventional operations in known onshore fields in the Lower 48 states,future infill drilling and waterflood projects in knownonshore fields in the Lower 48 states,future EOR projects in known onshorefields in the Lower 48 states, andonshore and offshore crude oil fieldsremaining to be discovered in the Lower 48 states and Alaska. For some categories of crude oil resources, analyses were performed assuming two levelsof technology-implemented and advanced-described below for each resourcecategory considered. The reservoir data bases used in the assessment did notrepresent the entire U.S. resource base. Analyses were generally performed on asubset of reservoirs fully performed on a subset of reservoirs fully describedin the data base for each resource category. The results for each subset ofreservoirs were not extrapolated; i.e., the results presented correspond onlyto the effects specific to the reservoirs analyzed. In addition, this analysisconsidered only the impacts on crude oil reserves. Many of these regulationscould also affect the development of U.S. natural gas reserves, but theseeffects were not considered. Summary of Analytical Approach After currently proved reserves are produced by conventional (primary andproduced by conventional (primary and secondary) recovery methods, nearlytwo-thirds of the known U.S. oil resource (more than 300 billion bbl) willremain unrecovered (Fig. 1). Nearly 100 billion bbl is displaceable by waterbut left in the reservoir at the end of conventional recovery operationsbecause it has not been contacted by existing wells or swept by ongoingwaterfloods. Another 242 billion bbl is not displaceable by water; the recoveryof a portion of this resource depends on the application of tertiary recoveryprocesses. Although not all of this remaining resource in place could ever berecovered, it represents a substantial target for future advanced recoveryoperations. Analysis of the production potential of the known (alreadydiscovered) oil resource relies on the Tertiary Oil Recovery Information System(TORIS) developed by the Natl. Petroleum Council and maintained at the Petroleum Council and maintained at the U.S. DOE Bartlesville Project Office. JPT P. 72

A Brief History of the Wasson EOR Project

Summary Amoco Production Co. and its partners embarked on a CO2-based EOR project in 1982 at the Wasson ODC Unit (WODCU), Wasson field, Yoakum County, TX. Many years of studies and carefully coordinated planning preceded the project's approval. This paper reviews several aspects of the project and details the WODCU CO2 removal plant.

Predicting Wet-Steam Flow Regime in Horizontal Pipes

Summary Knowing or predicting the flow regime for a wet steam flowing in asteam-distributing network is important to the engineering, management, andeconomics of steamflood EOR projects. The flow-regime data of steam inhorizontal pipes were compiled and analyzed with Taitel and Dukler's model ofpredicting flow regimes for two-phase flow. These data were used to constructsteam flow charts, to determine the effect of operating variables on thetransitions of flow regimes, and to establish transition criteria for steamflow in horizontal pipes. Introduction All steam EOR projects involve a steam-distribution system. Most steam usedin oilfield steam stimulation and steamflood operations is a wet steam, withvarious levels of quality. It is classified as a two-phase fluid. Many aspectsof two-phase flow behavior - such as frictional pressure loss, liquid holdup, and phase splitting at piping tees - are affected by the flow regime existingin the distribution system. Predicting the flow regime is important to theefficient and effective operation of oil recovery projects. However, the flowregimes are much more complicated for two-phase fluids. To date, no method orchart has been published specifically for the prediction of wet-steam flowregimes. This problem can be addressed either through experiments or byadapting a general flow-regime prediction technique developed for two-phaseflow. The latter approach is used in this study. After several techniques 1–3for predicting flow regimes of two-phase flow were reviewed and compared, Taitel and Dukler's Model was selected for steam flow. The flow regimes of wetsteam flowing in horizontal pipes are presented here. To facilitate thecomputation of the flow regimes, a two-phase-flow computer program based onTaitel and Dukler's model was used. These flow-regime data are then used toconstruct steam flow charts, to determine the effect of steam quality andoperating variables on flow-regime transitions, and to establish criteria forthese transitions. This study covers steam pressure ranging from 200 to 2,000psia [1.38 to 13.8 MPa]; steam quality, from 2 to 90%; pipe size, from 2 to 24in. [5 to 61 cm] (Schedule 80); and steam flow rate, from 50 to 620,000 B/D [8to 98 600 m3 /d] cold water equivalent (CWE). A pipe roughness of 0.001 in.[0.025 mm] was used for all pipes except where specified. Steam properties arebased on those listed in the steam tables. Taitel and Dukler's Theoretical Model Taitel and Dukler classified horizontal two-phase flow into five flowregimes: stratified smooth. stratified wavy, intermittent, annular, anddispersed bubble (Fig. 1). In stratified smooth flow, the liquid phase flowsalong the bottom of the pipe, the gas phase flows along the top, and theinterface is smooth. In stratified wavy flow, the two phases are separated inthe same manner, except the interface is wavy. In intermittent flow, the liquidphase in the pipe is distributed nonuniformly along the flow direction. Plugsor slugs of liquid are separated by gas bubbles or vice versa. In annular flow, sometimes also called annular dispersed or annular/mist flow. the liquid phaseflows as a film on the pipe wall surrounding a core of high-velocity gas phasecontaining various degrees of entrained liquid. Finally, in dispersed bubbleflow, the gas phase is distributed as discrete bubbles within a continuousliquid phase. Using physical mechanisms associated with the instability of asolitary wave, Taitel and Dukler developed a theoretical and empirical model topredict the transitions between flow regimes and presented those regimes in theform of a flow-regime map (Fig. 2).