EOR Process Research Articles

Combined Low Salinity Brine Injection and Surfactant Flooding in Mixed−Wet Sandstone Cores

The concept of surfactant flooding has long been recognized as a promising supplement to water-based enhanced oil recovery methods. In recent years, core displacement experiments performed on clastic rock samples using low salinity brine as injection fluid have proven to give a moderate increase in crude oil recovery. This paper presents a new hybrid EOR process where the effect of low salinity brine injection is combined with surfactant flooding. An anionic surfactant formulation was selected to give low interfacial tension (IFT) in a low salinity environment containing 0.50 wt % NaCl. The surfactant forms Winsor type I microemulsion at this salinity. Improved surfactant solubility and reduced adsorption or retention is among the advantages of using surfactant at low salinity conditions. This paper reports core flood experiments performed on outcrop sandstone cores using crude oil as the oil phase. Results show high oil recovery of more than 90% of original oil in place (OOIP) when surfactant is used in ...

Influences of Different Modes of Reservoir Heterogeneity on Performance and Oil Recovery of Carbon Dioxide Miscible Flooding

Abstract Reservoir heterogeneity represents one of the most dominant factors affecting the performance of CO2 miscible flooding and its expected oil recovery. The main goal of this study is to investigate the influence of different modes of reservoir heterogeneity on oil recovery by supercritical CO2 miscible flooding. The investigated heterogeneity modes include:different single fractured reservoirs of different inclination angles,different permeability configurations of layered reservoirs, andthe sequence of permeability distributions in composite reservoirs. Complete reservoir rock and oil compositional analyses were performed. The minimum miscibility pressure (MMP) of oil-CO2 was mathematically calculated using several empirical correlations and determined experimentally using slim tube tests. The core flood tests were achieved using actual fluids injected through 12 actual reservoir rock samples. Of these, four samples were of different fracturing angles as single fractured reservoirs, four samples were of different permeability configurations as layered rocks and four samples represented composite reservoirs. The slug size of supercritical CO2 was optimized to be 0.15 PV, injected and chased by actual reservoir brine through these different simulated modes of reservoir heterogeneity. The results indicated that all different modes of reservoir rock heterogeneity have a crucial influence on oil recovery by CO2 miscible flooding in carbonate oil reservoirs. Of note, unfractured reservoirs produced higher oil recovery by CO2 miscible flooding than single fractured ones. An oil reservoir with a 30 degree inclination angle of single fracture produced the highest oil recovery, whereas, fractured rocks with a 45 degree fracture produced the minimum oil recovery in this category. The rock permeability sequences of medium-low-high (MLH) mode for composite reservoirs and medium-high-low (MHL) distribution mode for layered reservoirs are highly recommended for CO2 miscible flooding. The results have proven the suitability of the CO2 application for layered and composite heterogeneous carbonate reservoirs, however, it does not recommend this EOR process for single fractured reservoirs. The results have also shown a real impact on oil recovery of the reservoir heterogeneity mode prevailing in the reservoir under development by this EOR process. Introduction The major applications of active carbon dioxide flooding projects were found in the U.S. Permian Basin, located in West Texas and Eastern New Mexico. Other projects were also active in Colorado, Louisiana, Mississippi, Oklahoma, Utah, Wyoming, and in Canada, Turkey (Bati Raman), Trinidad and Hungary (Budafa). The number of CO2 projects have increased in the U.S. and worldwide over the last number of years(1–3). Reservoir characterization has been considered one of the most important components of reservoir development because it provides a better description and distinguishes essential features of reservoir heterogeneities affecting fluid flow in pay formations. It has been proven that a better reservoir description and/or characterization reduces the amount of oil left in oil reservoirs. The main purpose of reservoir characterization is to outline and specifically integrate different forms of heterogeneities of the reservoir oil. Forgotson(4) defined reservoir characterization as the quantitative description of the physical and chemical properties of the porous medium and its contained fluids.

Polymer Flood Application to Improve Heavy Oil Recovery at East Bodo

Abstract The East Bodo, Lloydminster SS heavy oil pool has been exploited using primary recovery and waterflood. IOR screening showed that a polymer flood would be a preferred IOR technique. Subsequent coreflood tests indicated that the polymer flood could recover 20% OOIP incremental oil, after waterflooding, to a 95% water cut. Data gathered from the coreflood was used to fine tune the reservoir simulation model to help design the pilot and predict potential economic reserve capture for a commercial field-wide polymer flood. Subsequently, a pilot was initiated. During the pilot operation, achieving the target polymer viscosity, dependant on water quality, proved to be a significant challenge. Early field response is being observed through an increase in injection pressure, reduced water cut and polymer breakthrough. Further positive response of this polymer pilot allows for the expansion of the polymer flood technology to other parts of this reservoir; some with bottomwater and gas cap. This paper reviews the progress of the East Bodo polymer flood, from laboratory concept to working field application, in four major steps:IOR screening using simulations and coreflooding,field pilot design/implementation,pilot performance, andnext steps. Introduction Pengrowth has targeted East Bodo (Alberta side) and Cosine (Saskatchewan side) for waterflood optimization and subsequent enhanced oil recovery applications. Currently, the most practical EOR technology for this heavy oil reservoir seems to be the polymer flood technology in combination with horizontal wells. Several investigators(1–4) have demonstrated the potential of the polymer flood technology for improved oil recovery in heavy oil reservoirs. The East Bodo/Cosine Reservoir produces from the Lloydminster Formation, which is part of the Lower Cretaceous Mannville Group. Pengrowth provided some of the reservoir characteristics, as summarized in Table 1. This particular reservoir is separated into two parallel lobes trending North/West to South/East. To complicate matters, local gas caps are found primarily on the Saskatchewan side of the reservoir. Thus, the current waterflood patterns are located on the Alberta side. In the future, optimized waterflood and EOR schemes need to include those parts of the reservoir which are overlain by gas caps or influenced by bottomwater. A plan of progression aligned with the priorities of Pengrowth was laid out as follows:Optimize existing waterflood;Step out waterflood into limited gas cap areas;Then, target areas with a more extensive gas cap;Determine enhanced waterflood potential, for instance polymer flood; andArrange well patterns to benefit both waterflood and subsequent EOR process. IOR Screening Several IOR technologies were considered for application in the East Bodo Field. What follows is a list of IOR processes that were initially considered, but screened out after technical or economical issues could not be overcome.Thermal Recovery: Pay is too thin - heat loss to overburden is too large; oil not viscous enough to form a stable steam chamber; fireflood has potential, but a previous pilot on a neighbouring McLaren pool yielded poor results.

Use of reservoir simulation for optimizing recovery performance

A three-dimensional finite-difference reservoir simulator, integrated in an EOR expert system, has been used to determine the reservoir management and production strategies to optimize the oil recovery from a carbonate reservoir. The reservoir is a candidate for an EOR process or otherwise subject to abandonment. After screening the reservoir for an appropriate EOR process on the basis of its properties, it was determined that miscible carbon-dioxide injection is the most suitable process. The management strategies involved studying different design parameters to maximize the project profitability. The injection techniques that were tested in this study include: (1) water-alternating-gas (WAG), (2) simultaneous water-alternating-gas (SWAG) injection, and (3) gas injection in the bottom of the reservoir with water injection in the reservoir top. All simulation runs were conducted using permeability fields that have been conditioned with core data taken from wells in the field. Specific strategy that was used includes the use of horizontal injectors in conjunction with vertical producers. This well configuration has been shown to yield the best oil recovery compared to other well configurations. Simulation results show that the most economical method to produce this reservoir was to simultaneously inject water at the reservoir top and gas at the reservoir bottom. This production strategy has resulted in better sweep efficiency and therefore high oil recovery and good economics.

OPTIMIZING OIL RECOVERY IN A CARBONATE RESERVOIR THROUGH INTEGRATED RESERVOIR SIMULATION STUDIES

ABSTRACT A three-dimensional finite-difference reservoir simulator, integrated in an EOR expert system, has been used to determine the reservoir management and production strategies to optimize the oil recovery from a carbonate reservoir. The reservoir is a candidate for an EOR process or otherwise subject to abandonment. After screening the reservoir for an appropriate EOR process on the basis of its properties, it was determined that miscible carbon-dioxide injection is the most suitable process. The management strategies involved studying different design parameters to maximize the project profitability. The injection techniques that were tested in this study include: (1) water-alternating-gas (WAG), (2) simultaneous water-alternating-gas (SWAG) injection, and (3) gas injection in the bottom of the reservoir with water injection in the reservoir top. All simulation runs were conducted using permeability fields that have been conditioned with core data taken from wells in the field. Specific strategy that was used includes the use of horizontal injectors in conjunction with vertical producers. This well configuration has been shown to yield the best oil recovery compared to other well configurations. Simulation results show that the most economical method to produce this reservoir was to simultaneously inject water at the reservoir top and gas at the reservoir bottom. This production strategy has resulted in better sweep efficiency and therefore high oil recovery and good economics.

THAI-New Air Injection Technology for Heavy Oil Recovery and In Situ Upgrading

Abstract THAI-"Toe-to-Heel" Air Injection, is a new EOR process, which integrates advanced technology and horizontal well concepts, to achieve a potentially very high recovery of heavy oil. It can also realize very substantial in situ upgrading by thermal cracking, producing upgraded oil to the surface. The process operates in a gravity stabilized manner by restricting drainage to a narrow mobile zone. This causes the flow of mobilized fluids to enter directly into the exposed section of a horizontal production well. The process can be operated on primary production, asnew technology, as a follow-up to existing technologies, or asa co-process where the advantages of high thermal efficiency are equired. This is achieved by concentrating the energy required for oil mobilization, recovery and thermal upgrading in the reservoir. Combined with clean technology design, THAI offerspathway, to future economic success for the heavy oil industry. Three-dimensional, semi-scaled experimental tests on light "Forties Mix" oil (30.7 °CDATA[API), Clair, West of Shetlands medium heavy oil (20.8 °CDATA[API), and heavy Wolf Lake oil (10.95 °CDATA[API) show that a well-controlled, narrow mobile oil zone is created just ahead of the combustion front. The width of this narrow zone depends on the characteristics of the heavy oil at reservoir conditions and the degree to which the very high viscosity of the cold oil seals the horizontal producer well. Well sealing can be augmented by a novel sleeve-back technique, which allows perforated downstream sections of the well to be shut-in. The application of this technique enabled the light oil test to mimic the operation of a heavy oil reservoir using THAI. Very high oil recoveries were achieved in the tests, up to 85﹪ OOIP. During wet in situ combustion (ISC), Wolf Lake oil was upgraded to 20 °CDATA[API, achieving a reduction in the cold oil viscosity from 100,000 mPas to around 50 mPas. Introduction Horizontal and multi-lateral wells are being introduced in ever increasing numbers to achieve further gains in reservoir productivity. Two hundred horizontal wells were drilled a decade ago. Now, one company has reported drilling more than 2,100 horizontalwells in North America(1). Advances have also been achieved in the depths drilled, reaching 8,761m(2) and lengths now reaching up to 11 km. Multi-lateral wells, with four or more side-tracks, are not uncommon and offer further optimization gains. Moreover, this technology will accommodate reservoir faults and problems of structural geology as regular design factors so that strategic placement of the well path is achieved. More recently, a new technique to control gas and water production rates by varying the fluid entry points has been successfully tested(3). The most important advantage of horizontal wells is the increase in the reservoir contact area compared to a vertical well. Horizontal wells have created new possibilities for the implementation of advanced IOR methods, especially in thermal recovery.

Sensitivity Studies of Resistivity Monitoring for Shallow Enhanced Recovery Processes- A Numerical Case History

Abstract Enhanced Oil Recovery (EOR) processes have been monitored using gas analysis, geophysical logging, observation wells (pressure and temperature), well testing methods, seismic velocity tomography, and inversion of deformation measurements. Each of these methods has various strengths and weaknesses. Most EOR processes involve large changes in the formation resistivity because of the introduction of a fluid phase with a different electrical conductivity, or because of a large temperature change. These massive changes in subsurface conductivity may be monitored remotely using subsurface-to-surface resistivity techniques to investigate propagation of fluid fronts and growth of affected zones with time. In this paper, we present general requirements for resistivity techniques in EOR monitoring, typical electrode installations to reduce noise and seasonal variations, and approaches to the inversion of three-dimensional (3D) EOR resistivity problems. Sensitivity analyses for a real reservoir case subjected to EOR are presented, and a method of rapid design evaluation for resistivity monitoring is outlined. It appears that that the analysis tools and the technology is now adequate to systematically develop electrical monitoring for various EOR applications. Introduction Geophysical techniques have been used for reservoir delineation and description for several decades. Currently, attempts are being made to modify geophysical techniques to actively monitor secondary and tertiary recovery processes such as water injection, cyclic steam stimulation, and in situ combustion. In principle, changes in geophysical responses with time can be used to estimate the lateral extent and volume of the reservoir affected by the EOR process. Thus, the main objective of EOR monitoring is to provide reliable spatial and temporal descriptions of fluid or temperature fronts. These data may be supplemented with production and observation well histories to estimate recovery efficiency and to develop production strategies. In practice, high-quality remote geophysical data should lead to improved process control and greater recovery ratios because they represent independent measures of recovery behavior which can be used to guide production strategies. Case histories of reservoir monitoring based on 3D/4D reflection seismology (Greaves and Fulp, 1987; Pullin et al., 1987; King et al., 1988; Eastwood et al., 1994; Mathisen et al., 1995a and 1995b, Lumley, 1995, and many more), crosshole seismic transmission (Justice et al., 1989; Bregman et al., 1989), surface deformation inversion (Dusseault et al., 1993) and electrical methods (Dorfman et al., 1977; Bartel, 1982; and many more) have been reported in the literature. These studies demonstrate the feasibility of geophysically monitoring EOR processes. With technological advances and innovative techniques, one may expect that it will become possible to more reliably monitor chemical flood evolution, gas distribution changes, and hydraulically induced fracture propagation. The most widely used and successful geophysical technique for describing reservoir processes is surface 3D/4D reflection seismics. Compared to surface seismics, crosshole methods or vertical seismic profiling (VSP) have greater vertical resolution. They are important aids in calibrating surface seismic survey for use in lateral variation studies of seismic velocity, but are invariably more costly than surface methods. Surface, VSP and crosshole methods are based on ray-path tracing and analysis of velocity changes.

Application of a New Technique to Optimize Injection Gas Composition For the Rainbow Keg River F Pool Miscible Flood

Abstract A new experimental technique, called the Vanishing Interfacial Tension (VIT) technique, has been successfully utilized in this study to optimize solvent composition for the miscible gas injection project being considered for the Rainbow Keg River F Pool. The VIT technique consists of measuring the interfacial tension between the injected gas phase and the reservoir crude oil at the temperature of the particular oil containing formation and at varying pressures and/or enrichment levels of the gas phase. These interfacial tension measurements are carried out by computer digitization of the image of the profiles of sessile and pendant drops of crude oil enclosed in a surrounding medium of the injection gas. By fitting these experimental drop profiles with the iterative solution of the Laplace capillary equation, the value of the interfacial tension is obtained at each pressure or enrichment level. By making a plot of the interfacial tension against the independent variable (either pressure or enrichment), accurate values of the minimum miscibility pressure (MMP) and/or the minimum miscibility composition (MMC) are obtained by extrapolation to zero interfacial tension. This paper describes the new VIT technique and provides experimental evidence for its validity by comparing the VIT-MMP with slim-tube-MMP. Each MMP determination using the VIT technique was accomplished within 4 – 6 hours, while 4 – 6 weeks were required for the slim-tube technique. The paper also describes the application of the VIT technique to the problem of optimizing the injection gas composition at the Rainbow Keg River F Pool miscible flood. For this field application of the technique, live reservoir crude oil as well as lean and rich gas mixtures, matching field gases in composition, were used in the experiments. Gas/oil interfacial tension measurements were made in "first contact" as well as "equilibrium" modes. The optimized solvent composition was then verified by a single slim-tube test and compared with equation of state predictions. It has been demonstrated through this study that the new VIT technique is a reliable, accurate and fast technique for cost effective determination of MMPs and optimum injection gas compositions. Introduction Hydrocarbon miscible flooding is by far the most important conventional oil EOR process in Canada. It accounts for 83% of the 164,600 b/d of Canadian conventional oil EOR production(1). Furthermore, it is worth noting that most of the 104,300 b/d EOR production increase in 1992 (over that in 1990) in the US was also due to miscible projects based on both CO2 and hydrocarbon gases(1). Further improvements in the economics of miscible flooding could be accomplished by minimizing the cost of solvent blends and the cost of their injection. These can be achieved by (1) optimizing the solvent composition so that minimum enrichment of the dry gas by the C2+ fraction would yield cheaper solvents for injection and enable increased sales of the natural gas liquids, (2) increasing the accuracy of determination of minimum miscibility pressures for a given solvent composition and reservoir temperature which, in turn, would enable operation at near miscible conditions resulting in considerable compression cost savings.

Evaluation of Fractal Models To Describe Reservoir Heterogeneity and Performance

Summary Our work uses fractals to characterize the spatial correlation structures of porosity and permeability of vertical and horizontal logs in a braided-fluvial sandstone reservoir. The data comprise cores and logs of adjacent vertical wells and logs of horizontal wells. Small-scale realizations of interwell heterogeneity were generated with successive random additions (SRA) technique for new observed fractal models. A deterministic description is also developed. Effects of fractal and deterministic reservoir heterogeneity on reservoir performance were studied for waterflood and water-alternating-gas (WAG) injection processes. The effects of scale up on spatial correlation of porosity was investigated. The fractal model of fractional Brownian motion (FBM) in the horizontal direction, having same intermittency exponent as for fractional Gaussian noise (FGN) in the vertical direction, is not supported by log observations in horizontal wells. Fractal character of core and log data of vertical wells is similar. The incremental WAG recovery response compared to waterflooding response is more sensitive to reservoir heterogeneity. Scale-up experiments indicate that spatial correlation structure of reservoir properties may be different at different scales. Results of this paper will be useful for evaluation of infill drilling, and design, selection, and optimization of an EOR process. The proposed techniques also provide a framework to quantify uncertainty in reservoir performance.

Performance Analysis and Optimization of the Prudhoe Bay Miscible-Gas Project

Summary Because EOR oil response at Prudhoe Bay has been difficult to measure directly, a number of different types of field measurements have been made to evaluate the miscible-flood displacement efficiency. These measurements include water- and solvent-injection profiles, logging data from an observation well, and single-well tracer test (SWTT) data. Despite ambiguity in these data, the measurements support the simulation and laboratory data and generally indicate that the Prudhoe Bay Miscible Gas Project (PBMGP) is performing well. The most useful EOR surveillance data have been the separator-gas-sample database, with ≈4,000 compositional analyses. Separator flash analysis and allocation programs use this database to infer EOR performance on the basis of produced solvent. Reservoir mechanisms that adversely affect the EOR process efficiency have been identified. The project has exceeded initial expectations in terms of solvent retained within the reservoir, which has favorable implications for solvent sweep efficiency. Procedures have been developed to use the field and simulation data to determine how the solvent should be allocated to the existing patterns and when the project should be expanded into new areas. These procedures are designed to maximize the value of the PBMGP.

Design of a Gravity Assisted Immiscible Gas Injection Program For Application In a Vuggy Fractured Reef

Abstract The potential of gravity assisted immiscible gas injection was evaluated for a waterflooded vuggy fractured reef. Extensive laboratory work was carried out for the study of the effects of wettability and heterogeneities on recovery. Tests were performed on 2-D glass micromodels, unconsolidated systems and reservoir core plugs. The recovery due to gas injection was correlated to the recovery due to waterflooding for each test. The laboratory results indicate that an incremental recovery of up to 20% original oil in place (OOIP) should be expected from gas injection even from a heterogeneous fractionally wet formation. In this paper, an overview of the laboratory and preliminary design work is presented. A discussion of the mechanisms that take place during the gravity assisted immiscible gas injection in a fractured vuggy reservoir with fractional wettability is also included. Introduction Gas injection is the oldest of the fluid injection processes. The intention of recent gas injection projects has been to increase the ultimate recovery and therefore gas injection can be considered an enhanced oil recovery process. Gas injection may be either a miscible or an immiscible displacement process. In this paper only immiscible gas injection is considered. Of particular interest to this work is the immiscible injection gas in the carbonate reefs of Western Canada. The primary problems with gas injection in carbonate reservoirs(1) are the high mobility of the displacing fluid and the wide variations in permeability. Much greater control over the injection process must be exercised than is necessary with waterflooding. The benefits obtained by the gas injection are dependent upon horizontal and vertical sweep efficiency of the injection gas. The sweep efficiency depends oil the type of porosity system present and on the gasflood design. In general, immiscible gas injection better suited to vertical displacement schemes than horizontal displacement schemes. Oil fields that have low oil saturation in either primary or secondary gas cap are prime candidates for improved recovery by gas injection into the gas cap(1). Further shrinkage of oil is reduced by gas injection. Inasmuch as it maintains a relatively high pressure gradient in the oil phase, relative permeability to oil remains high and oil is produced faster and in greater quantity. Considerable insight and a large number of demonstration experiments dealing with the use of gravity assisted immiscible gas injection (GAIGI) as a novel EOR process is given in Kantzas et al.(2, 3) and in Chatzis et al.(4). In these references description of the pore level mechanisms are given and extremely high recoveries of waterflood residual oil are reported for unconsolidated systems. Also high recoveries are reported for Berea sandstone. It was explained that when oil spreads on water, the invasion of gas displaces residual oil from large pores in water-wet systems. This oil forms a thin film which becomes thicker as the displacement evolves. An oil bank is finally formed which flows downwards and sweeps the reservoir. This approach extends gas injection strategies to reservoirs which are too shallow for miscible floods. Also it avoids the use of any expensive surfactant systems.

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.

Predicting performance of steam floods with analytical models

Analytical steamflood models have been around for over three decades begininng with Marx and Langenheims classic SPE paper in 1959. The availability of personal computers in recent years has resulted in publication of a number of more sophisticated models, which more accurately depict the EOR process. Unfortunately, along with this added ability comes added complexity and the danger of misapplication. Two of the more popular examples of this genre are by Jones in 1981, and Gomaa in 1980. Each has been reviewed in the literature several times over the years and quite often each has been misapplied. Thus to aid in application of these models, this paper investigates a few steamflood projects to illustrate proper use. It is not the purpose of this paper to provide an exhaustive analysis of any particular model, but to demonstrate that these models can yield very good results if properly applied.

Application of the cross-borehole direct-current resistivity technique for EOR process monitoring - a feasibility study : Beasley, C W; Tripp, A C GeoexplorationV28, N3/4, Oct 1991, P313–328

Application of the cross-borehole direct-current resistivity technique for EOR process monitoring - a feasibility study : Beasley, C W; Tripp, A C GeoexplorationV28, N3/4, Oct 1991, P313–328

Enhanced Recovery Under Constrained Conditions

This article discusses conditions favorable for the application of enhanced recovery activities in the energy industry. The author focuses on the enhanced recovery of oil. The estimated worldwide in-place gas and oil volumes by geographic areas are estimated.

Sequential Steam: An Engineered Cyclic Steaming Method

"The Potter Sand... has responded well to virtually all thermal recoverymethods... Cyclic steam, however, has been the best EOR process for selectedleases." Summary Cyclic steam injection has been the most widely used EOR method in areas ofthe Potter sand in the Midway-Sunset field, Kern County, CA. This paperdiscusses the field pilot and the statistical and theoretical studies leadingto the design of a sequential steaming process, plus the implementation of thisprocess on three leases. Introduction Oil is produced from many different sands in the Midway-Sunset field, andthermal EOR is the predominant recovery method. The Potter sand. the mostprolific reservoir in the field. has responded well to virtually all thermalrecovery methods. including steamdrive, in-situ combustion. and cyclic steamstimulation. Since the early 1960's, Santa Fe Energy Co. has experimented withall these methods in the Potter sands with varying degrees of success. Cyclicsteam, however. has been the best EOR process for selected leases. Indeveloping our cyclic steam technique. we devised a method called"sequential steam that we feel is a superior way to process these thick, steeply dipping, heavy-oil sands. Geology The Potter sands. the primary producing zones in the northern end of theMidway-Sunset field (Fig. 1), are in the upper portion of the Reef Ridgeformation of Late Miocene Age. According to Lennon, the sands are predominantlya series of fan-channel complexes formed during rapid subsidence of the basin. Coarse granitic debris from the coastal range flowed down marine canyons into adeepwater fan. The depositional character of the Potter is extremely variable, ranging from massive, conglomeritic. debris-flow-filled, narrow channels tothinly bedded, laterally extensive, very-fine-grained, distal-fan turbidites. The subsidence produced a generally transgressive sequence; that is, thedeeper-water. thinly bedded deposits tend to overlie stratigraphically thecoarser, shallow-water channels. Subsequent uplift and tilting produced anerosional surface upon which the Pleistocene Age lacustrine and alluvial-fanTulare formation was deposited. The final uplift and erosional sequence leftthe Potter sands in the setting shown in Fig. 2. The producing sands outcrop atthe western limit of Potter production and are covered by a rapidly thickeningwedge of Tulare silts and sands toward the east. Dips range from about 40 atthe west to 20 at the east and trend north to east. Net sands also are highlyvariable. In the northwestern region of Potter production, especially in the 21Fee lease (see Fig. 1 for all lease locations), where the deposition ispredominantly debris-filled channels. The few existing permeability barriersare discontinuous (presumably caused by channel scour) and often will notcorrelate along strike from one well location to the next. Consequently, netsand counts range up to 700 ft, with as little as 50 ft of shale intervals. Thedeltaic distal-fan deposits to the east are finely interbedded sands and shaleswith individual members ranging in thickness from inches to tens of feet. Netsands may total less than 100 ft in a gross interval of 200 Common reservoir properties in these leases are low-gravity crude (11.5 to13 API). fairly steep dips, good lateral permeability between well locations, low water cuts (~40%). an inactive aquifer. and a reservoir mineralogyapparently highly resistant to damage by steam. History Upstructure Potter Sand Steamflood Pilots. Santa Fe began cyclic steamoperations in the Midway-Sunset field in early 1964. Well No. 36, 27 USL lease, was steamed with a 150-psi tank heating boiler. That first cycle experiencedpeak oil rates of nearly 200 B/D and convinced us that steam was a veryattractive EOR method in this reservoir. The first steamdrive in the area ofinterest began in Aug. 1967. Pilot 201–27 Fee was a single inverted five-spot(see Fig. 1) in an upstructure attic location. Unfortunately. as shown in Fig.3, the project performed poorly, with an instantaneous incremental steam/oilratio (SOR) of more than 9 bbl/bbl [fuel/oil ratio (FOR) of 0.73] during itsbest performance in 1969 and 1970. Cumulative incremental SOR performance wasabout 17 bbl/bbl (FOR of 1.3). Note that once steam decreased to a ratecommensurate with the observed production rate, all response was lost. Apostaudit of this drive showed conclusive evidence of uncontrolled steam lossto the upstructure air zone, which is laterally unbounded for all practicalpurposes. JPT P. 848⁁

Introducing EOR Technology to Independent Operators

Summary This paper describes how the Tertiary Oil Recovery Project (TORP), a research group at the U. of Kansas, stimulated application of permeability-modification techniques by independent oil operators through effective technology transfer. As of Spring 1987, TORP had worked with operators on 21 gelled-polymer field treatments. Three of the projects are described to illustrate the technology and the university/industry program. Introduction EOR processes have not been widely used by independent operators in the U.S. because of unavailability of reservoir data, limited equipment resources, and concerns that the technology cannot be applied successfully. In addition. limited financial resources inhibit the application of EOR processes in small fields. While some independents have staff engineers who can implement EOR, most cannot afford the expense of adding professional personnel whose sole purpose is to design and implement EOR processes. Further, the cost of laboratory research and engineering studies is usually prohibitive. When EOR processes are initiated but results are marginal owing to lack of capital or poor process performance, the operator is not able to continue the process and reverts to previous practices in the day-to-day operation of the lease. The net result is that potentially recoverable oil is lost by the plugging and abandonment of many stripper wells. Currently, many major oil companies are selling leases in the U.S. midcontinent region. An independent oil operator can often make money on these leases for a limited time because operation overhead is lower than that of a major company, but these leases will have to be abandoned by the independent in a short time. The leases might have the potential for continued economic operation if the appropriate EOR process were applied to the reservoir. This paper reviews some of the problems independent oil operators face when trying to implement EOR processes and presents an example of how TORP has successfully introduced one type of EOR application to small operators. Constraints Independent oil operators face constraints that make implementation of EOR processes very difficult. These constraints vary with individual operators; however, some of the most common are unavailable reservoir and production data, limited equipment resources, and concerns that a process cannot be applied successfully. Many independent operators feel that all EOR processes are very expensive or that the processes may not be applicable to their reservoirs. Although some EOR processes are capital intensive, a few are affordable to the independent operator and can be implemented successfully. The cost and type of process implemented depends on the type of reservoir problem. Individual well and lease records are essential to determine applicability of particular processes. On many leases operated by independents, however, insufficient data exist to determine production problems. Many independent operators have reduced overhead by not conducting individual well tests and/or not replacing broken metering devices. Although lifting costs are reduced in the short term, the lack of data to define the reservoir and production problems decreases the potential of the project. Equipment resources are another problem. Leases are often operated with a minimal amount of equipment and maintenance to reduce overhead. With limited technical staffs to assess the applicability of equipment, independents often rely on information from the equipment vendors, who are not always sufficiently knowledgeable of the independent operator's specific needs and equipment problems. In summary, before independent oil operators will use an EOR process, they must hurdle these constraints and have confidence that the process can be successful. They cannot afford major expenditures without a reasonable payout period. If capital must be borrowed, the lending institution must also be convinced that the process will be economically attractive. Implementing an EOR Process In 1974, TORP began a program to acquaint oil producers with the technical and economic potential of enhanced recovery methods. In the process, TORP started a field liaison program in 1983. With the help of an advisory board composed mostly of independent oil operators, the liaison program immediately developed a rapport with a number of operators in Kansas and began assessing the problems that operators face. Many independents in Kansas were found to have a common problem. JPT P. 1344^

Reply to Discussion of the 1984 Natl. Petroleum Council Studies on EOR

Reply to Discussion of the 1984 Natl. Petroleum Council Studies on EOR

Improving Chemical Flood Efficiency With Micellar/Alkaline/Polymer Processes

Summary A laboratory study was undertaken to find more efficient, lower-cost chemical systems for the recovery of waterflood residual oil. Our investigation emphasized alkaline-augmented processes because alkali is much less expensive than surfactant. The strategy was to replace some of or all the high-cost surfactants in a micellar formulation with lower-cost alkali and still maintain the high tertiary oil recoveries obtained with micellar flooding. Baseline oil recoveries in Berea corefloods were determined for two interfacially active crude oils with micellar/polymer (MP) and alkaline/polymer (AP) systems. A combination process was then developed in which a small micellar slug is injected first, followed by a larger AP slug. This process is referred to as a micellar/alkaline/polymer (MAP) flood. Phase-behavior studies guided the design and optimization of all three chemical processes in the coreflood experiments. Detailed effluent analyses and in-situ mobility measurements provided information about possible oil recovery mechanisms. Well-designed MAP systems recovered more possible oil recovery mechanisms. Well-designed MAP systems recovered more than 80% of the waterflood residual oil, comparable to the best MP systems These recoveries were achieved with only one-third the surfactant and cosurfactant required in the MP system. AP systems recovered less oil than either the MAP or MP systems. The chemical efficiency (ratio of the total chemical cost to oil recovered) of the MAP systems was better than the efficiency of the MP systems and comparable to that of AP systems. Similar results were obtained for both crude oils. Introduction Micellar flooding has received much attention in laboratory studies and field tests in recent years. This process is attractive because the displacement efficiency of an effective micellar flood can be almost 100% in zones swept by surfactant. However, this EOR process has yet to be implemented on a commercial scale because process has yet to be implemented on a commercial scale because of economic considerations. A recent Natl. Petroleum Council study I of EOR in the U.S. projects that the production from chemical flooding with current technology will be only 17% of production from all EOR processes. Micellar flooding alone is not likely production from all EOR processes. Micellar flooding alone is not likely to begin widespread application until the 1990's and will account for only 14% of future EOR. One major impediment to the commercialization of micellar flooding is the high cost of the surfactant and cosurfactant required to mobilize the residual oil in the reservoir. In this paper, our objective is to reduce the amount of surfactant needed for an effective chemical flood. Specifically, we investigated the use of inexpensive alkaline agents as substitutes for the more expensive surfactant chemicals. The results of this study are used to compare the performance and characteristics of the combined surfactant/alkaline performance and characteristics of the combined surfactant/alkaline process with that of surfactant and alkali alone. Others have reported a beneficial synergistic effect from combining surfactant and alkali in a chemical flood. When properly designed, adding surfactant to the alkaline slug can increase oil recovery significantly in laboratory corefloods. With polymer included for mobility control, the oil recovery can be as high as that obtained with a conventional micellar flood. Some authors suggest that the proper combination of these chemicals lowers interfacial tension (IFT) and reduces surfactant adsorption. Other possible benefits from alkali include a favorable change in wettability possible benefits from alkali include a favorable change in wettability and enhanced mobility control from the creation of emulsions. Two California crude-oil/brine systems (denoted A and B) were selected for this laboratory study. Initial work identified an MP system that displaced Oil A well in laboratory coreflood tests. Similar experiments with Oil B and an AP system showed that this process effectively displaced this higher-acid-number crude oil. The next stage of our investigation focused on combining alkali and surfactant to improve the oil recovery and chemical efficiency for both candidate reservoirs. The objective for Reservoir A was to maintain the high recovery obtained for the existing MP design, but with a significant decrease in the amount of expensive surfactant and cosurfactant. The objective for Reservoir B was to improve significantly upon the oil recovery for alkaline or AP floods by adding a minimal amount of surfactant. As a result, an improved MAP process was designed for both reservoirs.

Experience with CO2 Eor Process in Hungary

In Hungary, the CO2 injection EOR technology began in the mid 1960s. Since then, this method has achieved a wide range of field applications. Its special feature is that there is no miscibility. This article describes two types of field application: using CO2 in sandstone reservoirs and in karstic- limestone ones. The mechanism of displacement in such reservoirs is quite different. This article summarizes the exploitation technology used and its development, field experience and results, considering sandstone and the karstic reservoirs separately.