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Results
Abstract This paper presents an update of "The Jobo Steamflood Project-Evaluation of Results". Although an adverse condition, such as the presence of a strong natural water drive in this reservoir, which prevents pressure depletion by primary steam stimulated production, 41.5% of the STOOIP has been produced, from an estimated final recovery of 45%. Results from this mature project include a geological description of the oil bearing formations, basic petrophysical and fluids properties, a summary of oil production/steam injection statistics, well completions including thermal insulation of steam injection wells, surface facilities and associated processes with emphasis in recent technological developments, and analysis of front tracking schemes and their results. Since preliminary results of this project were presented, substantial knowledge has been gained, which is being used in the planning of commercial development of Venezuela's huge Orinoco Belt. Introduction The Jobo Steamflood Pilot Project (JSPP) represents an important step in the development of the appropriate technology for exploitation of the vast amounts of extra-heavy and non-conventional oil contained in the Orinoco Belt. The exploitation scheme of this 1.2 ร 10-12 bls (1.9 ร 10-11 m3) of oil in place will consist of successive steam stimulation cycles before beginning a steamdrive. The JSPP Project was carried out in the Jobo Field, in order to use existing infrastructure and because reservoir and fluids characteristics are essentially identical to those prevailing in the oil accumulations of the Orinoco Belt. PROJECT OBJECTIVES The JSPP was conceived with the purpose of obtaining information for future commercial development planning of this particular reservoir, and of the Orinoco Belt. The main objectives to be accomplished are:โEvaluate technical and economic feasibility of steamdrive. The presence of a natural water drive in this reservoir prevents pressure depletion by primary steam stimulated production. Nevertheless, if the steamflood is successful under this original pressure condition, it would guarantee success in the Orinoco Belt under depleted pressure conditions. โDetermine recovery factor. โCalibrate numerical simulators which will be of great help in comparing exploitation alternatives. PROJECT DESCRIPTION Location The JSPP is located in the Jobo Field, South of the State of Monagas in Eastern Venezuela, and just North of the Orinoco Belt, as seen in Fig. 1. Geology The Jobo field reservoirs belong to the Oficina Formation, which is divided into the Pilon, Jobo, Yabo and Morichal Members, as seen in the stratigraphic section of Fig. 2. The project is in the "C" sand of the Morichal Member because of its best quality and thickness. P. 723^
Abstract This paper describes the industrial pilot results of foam flooding for enhanced oil recovery. The results are explained by the laboratory results obtained. Based on the experiences of the single well foam-flooding results on the Lao Jun Miao field in northwestern China. an industrial pilot foam-flooding operation was carried out in the middle of the reservoir in this field in October 1979. This pilot operation involved IS production wells and 8 injection wells. The area of the pilot operation was 1.23 km. A response was obtained from a small number of the production wells. but no response was obtained from the other wells even two years later To analyze and explain the above-mentioned pilot results. the laboratory experiments were performed. The laboratory conditions were the same as those in the industrial pilot operation. The core sample was divided into two parts. One was swept by the conventional method. and the other was remained under its natural conditions. It was found that the precipitation occurred between the foaming agent and the water injected before the solution formed by foam with air. The amount of the precipitation depends on the concentration of the foaming agent and the salinity. The solubility of the foaming agent can be improved by adding SP-3 to the solution. The dispersion coefficient of the foaming agent (K,) between the crude oil and the formation water was equal to 1.5 in the presence of three phases. The K between the solid and the liquid present in four phases was greater than K. The adsorption isotherm of the foaming agent did not correspond to that of Langmuir's model. It had a maximum value at the critical micelle concentration (C.M.C). The adsorption decreased in the presence of SP-3 and SP-6 in the foam solution. In principle it was found that the foam was no longer formed farther than 10 meters from the injection well. The last part of this paper describes the results of simulation using a mathematical model. They correspond to the results of the industrial pilot and the laboratory results. Introduction The formation L, in Lao-Jun-Miao oil field located in Gansu (province), north-west of China, has been developed since 1939. So far 35% of the original oil in place (OOIP) have been produced The total percentage of water cut is 87%. The oil production decreased year by year. In order to increase the volumetic sweep efficiency, increase the total production, and enhance the oil recovery, according to the experiences performed in the single well test, a foam flooding field test in commercial extent at the middle limb in the eastern region of the oil field started in October 1979. In the pilot area, there were 8 injective wells and 18 production wells, it is an irregular five-spot pattern and the trapping area is 89 hectares (Fig.1). The depth of the oil-bearing formation is 670 m. The average effective pay thickness is 4.9 m. The average porosity is 20% and the average permeability is 1310 Sd. The original oil saturation is 84%, and the temperature of the oil-bearing formation is 28C. The 50.5% of the OOIP had been withdrawn before the test. The reservoir rock is the slightly cemented fine sandstone. The clay content is about 13.3%. It had been obtained by x-ray diffraction analysis that the clay contains dominantly the montmorillonite with the content of 51.30. Then it contains in turn 33% of illite, 12.3% of kaolinite, and 3.4% of chlorite (Tab.1). It had been identified by scanning electron microscopic analysis that the clay cement is in pore-filling form, and the montorillonite covered the surface of the grains in streching form. The composition of the rock grain is shown (Tab.2). The content larger than 80 meshes in diameter is about 74%. P. 709^
- Asia > China (1.00)
- Europe > Norway > Norwegian Sea (0.44)
- Geology > Mineral > Silicate > Phyllosilicate (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.34)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid management & disposal (1.00)
- Reservoir Description and Dynamics > Reserves Evaluation > Estimates of resource in place (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
Abstract This paper presents field test results of sixteen steam soaked wells in which the injected steam was treated with two different surfactants selected in the laboratory as being the most suitable to he applied under Bolivar Coast Conditions. The laboratory research was done by Shell Laboratorium (Netherlands) and Intevep-PDVSA Research Center (Venezuela) and the main selecting criteria was the pressure drop measured in the porous media during steam Foam Flow tests. The two steam Foam Formulations selected were, a long-chain alkyraryl toluene sulphonate (SURFACTANT 1) and a branch-chain alkyraryl benzene sulphonate (SURFACTANT 2). The SURFACTANT 1 was used in nine wells while the SURFACTANT 2 was injected in seven. The stimulation mechanism of SURFACTANT 1 seems to be steam diversion to the less produced sands and for SURFACTANT 2 it appears to be a change of interfacial properties in the water-oil-rock system. Although most of the steam foamed wells had not completed the production cycle, it can he concluded that 60% of them have presented positive response to steam foam. The initial oil rate response was equal to or slightly greater than that expected from a normal cycle, but steam Foamed wells produced up to three times the additional cumulative oil expected (75,000 bls vs. 25.000 bls for a third cycle). This is due to the fact that the decline of the oil production rate was lowered to about 12% pa. which is indeed close to that of primary production. The better oil production performances were obtained when the steam penetrated deeper into previously non productive layers. The maximum diversion registered was close to 90 feet as compared to 35 feet of the initial profile. Introduction Steam soak has proved to be a very efficient re-recovery process in the heavy oil reservoirs on the Bolivar Coast In Western Venezuela. The effectiveness of this method is intimately related to compaction which is the main production mechanism in these reservoirs. In order to minimise the benefits obtainable from this method the oil production should ideally come From all the sands of the reservoir. Nevertheless, the challenge of uniformly distributing the injected steam to each productive sand has been one of the greatest operational problems, At present selective injection is accomplished by the installation of special mechanical completion equipment, but this procedure complicates production operations thereby increasing costs. in order to enhance the steam injection profile and increase the recovery from heavy oil reservoirs, a programme was initiated to evaluate the use of foaming agents to reduce the mobility of steam. Laboratory tests carried out using values of steam quality, steam injection rates, pressure and temperature representative of the prevalent conditions in the Bolivar Coast, resulted in the identification of two appropriate surfactants. There upon a programme of field tests was initiated in Tia Juana, Lagunillas, and Bachquero in order to:Evaluate the capacity of the steam foam mixture to reduce the effective permeability to steam. P. 915^
- South America > Venezuela > Zulia (0.70)
- South America > Venezuela > Zulian Region (0.48)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.54)
- South America > Venezuela > Zulia > Maracaibo Basin > Tia Juana Field (0.99)
- South America > Venezuela > Zulia > Maracaibo Basin > Ayacucho Blocks > Lagunillas Field (0.99)
- South America > Venezuela > Zulia > Lake Maracaibo > Maracaibo Basin > Ayacucho Blocks > Bachaquero Field (0.99)
- (3 more...)
Abstract This is a comprehensive evaluation of the background, operations and results of applying the emerging steam-foam technology to two patterns of a mature steamflood suffering excessive steam breakthrough. Care was taken:to establish a valid baseline for injection and production before the treatments, to hold injection in the surrounding patterns at or below pretreatment levels, in order to isolate the causes of any oil rate increase, and to monitor in detail the two pilots over an extended period of time. Aspects of the project discussed include its design and implementation, the inferred reservoir mechanisms, the associated production operations and field performance, as well as the economics of the project. Introduction The Winkleman Dome Nugget steamflood is located in Fremont County, Wyo., and was initiated in 1964. The Nugget has good reservoir characteristics and it contains 14 API oil. A map with well locations is shown in Figure 1. Pertinent data, updated to August 1983, are to be found in the Appendix. A good discussion of the early performance of the steamflood is given by Pollock and Buxton. By 1983, some patterns of the Nugget steamflood exhibited severe steam breakthrough. Certain producing wells reached such elevated temperatures that they had to be shut-in or the amount of steam injected in the pattern had to be reduced. In either case, oil production was lost from the shut-in wells, or from the other pattern wells because of the reduced steam drive. In particular, the patterns centered around Injector Nos. 47 and 113 were experiencing the worst case of steam breakthrough. Steam breakthrough from Injector No. 47 to Well No. 39 occurred during February 1982. Producing temperatures on No. 39 reached 330F. The high temperature fluid caused severe emulsion and pumping problems and steam injection into No. 47 was cut from 417 BSIPD in March 1982 to 152 in April and to 60 BSIPD by October 1983. Concurrently, production in offset Producers No. 48 and No. 39 dropped by 130 BOPD. Similarly, steam channeling between Injector No. 13 and Well No. 38 resulted in Well No. 38 being shut-in on February 1983, when the wellhead temperatures reached 350 F. The high temperature created an oil-in-water emulsion that could not be treated. An attempt to produce it in April 1983 failed the tenth day, when temperatures reached 400F. Two subsequent attempts also resulted in severe steam breakthrough. It was decided to attempt to block the high permeability channels developed between injectors and producers by injecting a surfactant stable at high temperatures and exhibiting strong foaming behavior in situ. Eventually, two tests were done, the first in July-August 1983 (Pilot 1, injector No. 113) and the second in November 1983 (Pilot 2,, Injector No. 47). Their evaluation is the subject of this paper and the period surveyed is April 1983-July 1984. From May to July 1984, the Winkleman Dome Nugget was gradually converted to a hot waterflood and reservoir conditions changed drastically, terminating the evaluation period. P. 691^
- North America > United States > Wyoming > Winkleman Dome Field (0.99)
- North America > United States > Wyoming > Nugget Formation (0.99)
- North America > United States > Colorado > Nugget Field (0.99)
Abstract A recent study (SPE paper 16728) described a preliminary investigation of the effects of some commercial gelants on reduction in CO2 permeability. That paper presented a method for examining gelant systems by vial tests, core tests, and two-dimensional, flow visualization studies in high-pressure, glass micromodels. For the preliminary study, tests were conducted with CO2, San Andres crude oil, and brine at 1500 psi and 105F to simulate west Texas/southeast New Mexico conditions. The micromodel studies were coupled with the core tests to assess the pore-level mechanisms responsible for permeability reduction. Each of these commercial gelant systems demonstrated some deficiency in the desired performance in the brine/CO2 systems under investigation. This paper presents follow-up lab-scale studies with newer gelant systems that are shown to be more stable under the same brine/CO2 conditions. Gelation kinetics are discussed, and results of core tests with a phenolic gel and a vinyl gel are described. These gels are more rigid than the gels first investigated, and the micromodel studies indicate that they are much more effective in remaining stationary in channels or high-permeability flow paths. Introduction Carbon dioxide flooding is one of the fastest growing enhanced oil recovery methods. It can be economically attractive despite the poor mobility ratio between CO2 and the oil. However, many CO2 field projects have experienced early gas breakthrough caused by reservoir heterogeneities, such as fractures, channels, or high-permeability streaks. When most of the injected CO2 enters high-permeability zones, oil recovery efficiency and the economics of the process are reduced. Several water-soluble chemical gelants have been proposed to restrict flow of fluids in high-permeability thief zones, especially in waterfloods. Many of the gelant systems proposed for this application include gel structures that are somewhat fluid. A recent study described a preliminary investigation of the effects of some commercial gelants on reduction in CO2 permeability. The commercial gelants that were evaluated included polyacrylamide and xanthan gum crosslinked with chromium(III) ion as well as acrylamide monomer that is polymerized and crosslinked in situ. Each of these gelants demonstrated some deficiency in the desired performance in the brine/CO2 systems under investigation. Results of the first study will serve as baseline experiments for the evaluation of improved gelants for CO2 flooding applications. This paper presents a follow-up study with newer gelant systems that were expected to be more stable under the same brine/CO2 conditions as in the prior study. Gelation kinetics and results of core tests with a phenolic gel and a vinyl gel are described. Since these gels can be more rigid than the gels first investigated, the goal of this work was to assess their effectiveness in remaining stationary in channels or high permeability flow paths during brine/CO2 water-alternating-gas (WAG) cycles. EXPERIMENTAL PROCEDURES Gelant Systems One of the polymers previously studied for this application, xanthan gum, was used in slightly modified tests in the current study. The xanthan gum polymer used was Pfizer FLOCON 4800P, which is a broth containing 4.7% active polymer. Solutions of the xanthan gum polymer were crosslinked with Pfizer X-LINK 1000, a proprietary solution of chromium(III) ion. This gelant system will be designated XG/Cr. P. 115^
- North America > United States > Wyoming > Bighorn Basin > Phosphoria Formation (0.99)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- (22 more...)
Abstract Laboratory testing and evaluation of a new chromium(III) [Cr III] acrylamide-polymer gel technology for conformance-improvement-treatment (CIT) use are reported. This paper is primarily limited to discussing the gel technology as applicable to fracture conformance problems. Several notable features of the gel technology are as follows. The gels, as injected in the field, are a single fluid system. Gels are made by simply adding a single aqueous crosslinking-agent solution to the aqueous polymer solution. The base chemical of the cross-linking agent is a readily available and relatively inexpensive CrIII chemical. An entire family of CIT gels, ranging from highly flowing to rigid rubbery gels, can be produced by varying the formulation of the same chemical set. Thus, the new gel technology is applicable to a wide range of conformance problems. Highly controllable gel times, ranging from minutes to weeks, are possible and can be preselected. Gels have been shown to be stable for extended periods of time when aged at temperatures ranging from 55 to 255F (13 to 124C]. Over the same temperature range, the gels have been shown to possess exceptional yield strengths (resistance to flow) and to be effective plugging agents. The gels are relatively inexpensive because they typically contain 98 to 99.7% water. with the remainder being low cost chemicals. Gels of the new technology are insensitive to oilfield interferences and environments, including H2S. They are compatible with all tested oilfield fluids and equipment and with all tested reservoir rocks and minerals. The gels can be made over a polymer solution pH range of at least 4.0 to 12.5. Gels can be formulated with low-molecular-weight polyacrylamide polymers when low viscosity (watery) treatment fluids are required. The gels can be chemically degraded (reversed). Laboratory studies are described which show the dependence of gelation rate and gel strength on the following parameters:polymer type, concentration, molecular weight, and hydrolysis level; polymer-to-chromium ratio; temperature; polymer solution pH; and salinity. Gels are shown to exhibit favorable phase-stability, shear, and leakoff properties. A new bottle-testing scheme is described. Bottle testing is used to effectively, rapidly, and inexpensively monitor in a semi-quantitative manner gelation rate and gel strength as a function of time over a broad range of temperatures and gel parameters. Gel viscosities, as determined by dynamic oscillatory measurements, are used to substantiate bottle-testing findings and trends. For selected rigid gels, gel breakdown pressures in porous media and yield pressures are reported. Introduction New Gel Technology The intent of this paper is to report on laboratory testing and evaluation of a newly developed, promising, and patented gel conformance-improvement-treatment (CIT) technology where aqueous gels are formed by crosslinking acrylamide polymers (polyacrylamide or partially hydrolyzed polyacrylamide) with a chromium(III) [CrIII] crosslinking agent. The cross-linking agent is a mixture of complex CrIII ions containing low-molecular-weight carboxylate anions, in association with other anions. The preferred carboxylate anion is acetate. The crosslinking agent, as added to the polymer solution, is predominantly an oligomeric chromium complex ion. The crosslinking agent is highly water soluble and readily mixes with acrylamide-polymer solutions. The preferred CrIII crosslinking-agent base chemical is relatively inexpensive and readily available in the form of a concentrated aqueous solution. Typically, the cost of the crosslinking agent during our field tests has run about 15 to 20% of the polymer costs. In contrast to highly toxic CrVI2-5, CrIII is relatively non-toxic and has been reported to be an "essential micronutrient" for humans. CrIII, in low concentrations, is relatively non-toxic to aquatic life. P. 99^
- North America > United States > Texas (0.67)
- North America > United States > Wyoming (0.46)
- Research Report (0.67)
- Overview > Innovation (0.34)
- North America > United States > Wyoming > Mountain Field (0.99)
- North America > United States > Utah > Mountain Field (0.99)
- North America > United States > Gulf of Mexico > Central GOM > East Gulf Coast Tertiary Basin > Green Canyon > Block 152 > Marathon Field (0.99)
- (4 more...)
Abstract A study of foams as gas-blocking agents in model porous media is reported. Foams are generated by displacing surfactant solution with gas, and tested by measuring gas permeability as a function of step-wise increasing differential pressure. The method gives a direct, in-situ measurement of foam gas-blocking ability which is sensitive to differences among surfactants tested. Contrary to some previous reports, no correlation is found between surfactant performance in gas-blockage tests and in bulk foam tests. It is suggested to employ the gas-blockage method for screening purposes instead of bulk tests in studies directed at obtaining maximum gas blockage of porous media. Introduction A foam is a dispersion of gas in liquid, usually with a surface-active agent present. Foams are not thermodynamically stable and ultimately decay into their constituent phases, but can be mechanically stable. The properties of bulk, or unconfined, foams have been studied extensively. When a foam exists inside a confining medium, the dimensions of this confining medium relative to the average bubble size determines the texture and properties of the foam. Typical bubble sizes are from about 10 mu m and up to several mm. Where confining diameter is large relative to this bubble size, such as in a pipe, the foam is similar to a bulk foam. Its flow behaviour can then be treated as that of a non-Newtonian, compressible single fluid. Where the diameter of the confining body is similar to, or smaller than, minimum bubble size, the foam exists as a network of elongated liquid lamellae rather than bubbles. This is the case in most reservoir pore systems. Such a gas-blocking foam cannot be treated as a single fluid, because liquid and gas flows by different mechanisms. Liquid flows as a continuous phase, but gas flows by the sometimes very slow process of continually breaking and re-forming the liquid films. This explains why gas may be completely blocked by foam in a porous medium, while the permeability to liquid is merely reduced in proportion to liquid saturation. The ability of foam to reduce gas permeability has led to its suggested application in a number of production processes, including CO2 flooding, steam flooding, and several well-treatment techniques. P. 449^
- Overview > Innovation (0.41)
- Research Report (0.34)
Abstract Improvement of the steam-injection process by surfactants or foaming agents has already been demonstrated in field tests. However, surfactants for steam-foam operations that perform well in tests at low temperatures often fail above 200C. Laboratory research on steam-foam processes as a means of profile modification in soak wells has been carried out with the aim of alleviating the temperature limitation. First, the effect of surfactant structure was studied. As a result, sulphonates, both aliphatic and aromatic, were selected for further investigations. Besides critical parameters such as steam quality and surfactant concentration, the effects of a non-condensable gas and electrolyte were screened. It was found that, for steam-mobility reduction by in-situ foam generation, surfactant concentration and molecular weight are the overriding parameters. The thermal stability of the new products were studied in detail and the most economic supply formulation of these surfactants was identified. A product providing the best balance of all these aspects was tested in the field in soak wells on a large scale. The data collected on surfactant structure and molecular weight make it possible to select surfactants with excellent performance combined with long-term thermal stability. This will enable successful extension of the steam-foam process towards the more extreme temperature conditions encountered in various fields in the world. Introduction Steam injection is the most widely used method for recovering heavy oil. The efficacy of the process can be increased by improving the aerial and vertical distribution of the steam. This can be accomplished by reducing the steam mobility. A method that has gained acceptance in the field is the simultaneous injection of steam and surfactants (foaming agents). Simultaneous steam/ surfactant injection finds application on a large scale in the USA and a successful field trial has also been reported for the Tia Juana field on the Bolivar Coast, Venezuela. Most of the experience gained so far with steam foam is related to shallow reservoirs, where moderate temperatures and pressures prevail. Elsewhere, however, (for example in Venezuela, Canada and W. Germany), much higher pressures and corresponding temperatures may be used. Furthermore, steam qualities differ varying from, for example, 50 to 60% in one region (California fields) and from 80 to 90% in another (Venezuela). The encouraging results obtained with surfactants in steam-soak operations in Venezuela at 200C induced us to carry out a laboratory study with commercially available but mainly newly developed exploratory steam-foam surfactants. The objective was to investigate the feasibility of steam-foam injection into wells with injection temperatures approaching 300C. This paper deals with the steam-foam performance and temperature stability of the products investigated as well as the implications of their application in the field. EXPERIMENTAL APPROACH Equipment and Procedures The steam-mobility-reducing capability of surfactants is deduced from the pressure drop over an (artificial) sandpack during steam-foam injection. A steam foam with low mobility exhibits a large pressure drop over the sandpack. P. 905^
- South America > Venezuela (1.00)
- North America > United States > California (0.50)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.48)
- Geology > Mineral (0.46)
- Materials > Chemicals > Specialty Chemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.69)
- South America > Venezuela > Zulia > Maracaibo Basin > Tia Juana Field (0.99)
- Europe > Russia > Northwestern Federal District > Komi Republic > Timan-Pechora Basin > Pechora-Kolva Basin > Usa Field (0.99)
Abstract Laboratory corefloods were run to explore the feasibility of foam to provide mobility and injection profile control in a stratified, heterogeneous North Sea reservoir. The objectives were to identify suitable surfactants, from over 100 commercial surfactants initially screened, which were capable of producing stable foam at North Sea reservoir conditions and, to quantify the influence of several reservoir and injection parameters upon foaming performance. The experimental apparatus essential for the laboratory simulation of foam generation and injection into porous media at reservoir conditions is described. The test results showed that, compared with brine injection alone, three surfactants were each capable of substantially increasing core pressure gradients in synthetic porous media, when injected with nitrogen gas at conditions of 4300 psig (29.6 MPa) and 230F (110C). Effective, resilient foams can also be generated within natural sandstone cores at injection velocities of 10 ft/d (3.05 m/d). Based on the surfactants evaluated in this study, the dramatic reduction in foam pressure drop (by up to 80 times) in the presence of the North Sea crude used, effectively precludes the use of foam to restrict water or gas channelling at North Sea pressure and temperature. Introduction Many North Sea reservoirs are characteristically highly stratified, and exhibit extreme permeability heterogeneity. For example, horizontal permeabilities in North Sea fields may vary from around 13 darcies to under 10 millidarcies over the reservoir interval. Usually producing fields in the North Sea require pressure maintenance by downdip water injection. In the future, injection of either nitrogen or miscible hydrocarbon gas may be used to improve oil recovery. Preferential advancement of injected water or gas will result in early breakthrough and an uneven sweep of injection fluid. As an example, reservoir simulation studies of two of the major units of the Brent Sands in a North Sea Field, Rannoch and Etive, (Fig. 1) illustrate the poor vertical sweep efficiency expected on water injection. After 3000 days, water cuts at the producing wells exceed 95%. Dealing with such anticipated volumes of water on the production platforms will eventually render water injection uneconomic. At this time a substantial volume of oil will remain in the lower permeability Rannoch layers. Injection of gas to recover some of the unswept and residual oil in the reservoir will suffer similar problems from gas channelling. Improved or increased oil recovery in such heterogeneous reservoir sands demands that the injection profile is more closely controlled. Two aspects of injection control have been identified:mobility control to offset viscous instability, and; profile control to correct uneven progress of displacement fronts. P. 433^
- Europe > United Kingdom > North Sea (1.00)
- Europe > Norway > North Sea (1.00)
- Europe > North Sea (1.00)
- (4 more...)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.46)
Clifford, P.J., U.K. Atomic Energy Authority SPE Member Abstract In simulating field performance of polymer and micellar flooding, it is frequently necessary to calculate the behaviour of chemical slugs which are small compared to the well spacing, and not much larger than the normal gridblock dimension. A polymer slug in a heterogeneous reservoir will then be subject to disruption from numerical dispersion, viscous crossflow and viscous fingering. The problem addressed in this paper is whether oil recovery from the slug can be simulated without an impracticable degree of grid refinement. Analytical modelling is used to explain the process of slug disruption by viscous cross flow in a layered reservoir, and to demonstrate the close relationship between crossflow and oil recovery. Some of the concentration fronts will spread even in the absence of dispersion. Numerical simulation is used to examine the sensitivity of slug behaviour to grid refinement, dispersion, slug size and viscosity and viscous fingering. It is shown how a coarsening of the gridblock structure leads to large qualitative changes in slug flow and the movements of polymer within the reservoir. However, it is also demonstrated that the quantity of incremental oil recovery is much less sensitive to numerical dispersion, over a wide range of likely slug properties. This allows a much more adequate calculation of polymer flood performance in very coarse grids than would be expected from the ratio of slug to gridblock size, and is most important in permitting practicable reservoir simulation of this EOR process. Introduction In many polymer or micellar flood enhanced oil recovery applications (EOR), the volume of the injected chemical is often much smaller than the reservoir pore volume. In stratified reservoirs, polymer solutions are injected as small volume slugs, with the aim of improving vertical sweep efficiency. In this case, the slug will be subject to disruption by several mechanisms acting simultaneously:vertical crossflow of polymer between layers; dilution of concentration fronts by fluid cross flow; dispersion of concentration fronts; viscous fingering of chase water into the slug. Simulation of the behaviour in a coarse-gridded reservoir model also introduces substantial numerical dispersion, which often cannot be removed without excessive computational cost. Given these complexities, it is important to examine which aspects of the behaviour can be adequately simulated in a coarse grid. In particular, is it possible to predict the incremental oil recovery with any accuracy in a practicable model? The mechanisms by which polymer recovers oil in layered reservoirs, and the observed effect of grid coarseness, are first discussed. Simulations are then carried out using the SCORPIO chemical flooding simulator (1), and with simplified reservoir models and polymer properties. The theoretical analysis of flows involved in slug disruption which follows, is based in part on work on characteristics by Zapata and Lake (2) investigating two-phase flow in layered systems. The discussion examines the case of small slug injection, which is more complex than continuous polymer injection. Viscous fingering of polymer in layered reservoirs is examined. It is proposed that the effects of instability in a two-dimensional layered reservoir differ from those in linear displacement. P. 873^