Honarpour, M.M. (Natl. Inst. for Petroleum and Energy Research) | Szpakiewicz, M.J. (Natl. Inst. for Petroleum and Energy Research) | Schatzinger, R.A. (Natl. Inst. for Petroleum and Energy Research) | Tomutsa, L. (Natl. Inst. for Petroleum and Energy Research) | Carroll, H.B. (Natl. Inst. for Petroleum and Energy Research) | Tillman, R.W. (Consulting Sedimentologist)
Geological heterogeneities controlling fluid production from the Lower Cretaceous Muddy formation in the Tertiary Incentive Project (TIP) and adjacent area in Unit `A' of Bell Creek field Montana were investigated. Production and Injection performance and production test data, as well as core, log, and structural data, were integrated to provide an improved geological/engineering model. The model was used to study the influence of the various scales and nature of geological heterogeneities on fluid flow and residual oil saturation distribution in the reservoir.
Information from primary production; initial production rate potential distribution; cumulative primary, secondary, and tertiary production; pressure transient test data; water injection front tracking; electrical resistivity changes due to depletion of residual oil; injectivity histories of injection wells; and areal simulations was integrated to identify fluid flow patterns and residual oil saturation distribution.
Production performance and oil saturation distribution in Unit 'A' of Bell Creek field were affected by critical multigenetic heterogeneities, such as stratigraphy and dimensions of facies, valley incisions into the best productive barrier island sediments, high-permeability channels, reduction in net pay due to diagenetic clay content, faulting and structural dip. These heterogeneities result in large production/residual oil saturation contrasts over small distances. Results of the study showed that the most productive part of Unit 'A' is associated with regions of well-developed high-energy barrier island facies (upper shoreface and foreshore); low amounts of diagenetic clay cement; and absence of structural discontinuities. The influence of nature and the scale of geological heterogeneities varied at different stages of oil recovery.
The understanding of reservoir performance in the barrier island system was improved by integrated multidisciplinary analyses of standard data and comprehensive approach to geological and engineering interpretation.
This study was performed as part of the continuing research by NIPER to characterize reservoirs developed within barrier island system in terms of geological and production behavior. The integration of geological and engineering models was emphasized. Raw data except core descriptions and petrographic analyses for this study were provided by Gary-Williams Oil Producer Inc.; however, all geological and engineering analyses and interpretations were performed by the authors.
Barrier island depositional systems comprise at least six giant oil fields in North America and, therefore, are of considerable economic importance. Major geological heterogeneities encountered in Bell Creek field and their influence on primary, secondary, and tertiary production have been previously discussed.
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.
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.
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.
Field testing results are reported for a new conformance-improvement-treatment (CIT) gel technology, where acrylamide polymers are crosslinked with a chromium(III) [CrIII] crosslinking agent. Results are reported for nine field tests performed in Wyoming's Big Horn Basin during 1985 and 1986. All nine treatments were designed to reduce conformance problems encountered in naturally fractured reservoirs. Seven were injection-well treatments, and two were production-well treatments. All nine field tests were operational and technical successes.
Significant amounts of incremental oil production were obtained following five of the seven injection-well field tests and at both production-well field tests. Peak incremental-oil-production rates resulting from the injection-well gel CITs ranged from 38 to 380 bbl/D [6.0 to 60 m3/d). The first production-well field test, in a carbonate reservoir, generated 7500 bbl [1190 m3 of incremental oil (beyond 4400 bbl [700 m3 of projected base oil production). The second production-well field test, in a sandstone formation, required a smaller than expected gel volume. The second treatment has generated over 14,000 bbl [2200 m3) of incremental oil and did pay out in five months.
Overall, the economics of the field testing program are encouraging. For the seven field tests which stimulated incremental production, incremental stock-tank oil production through May 1987 was 450,000 bbl [71,500 m3; and the production wells affected by these seven gel CITs were still producing at a combined incremental-oil-production rate of 780 bbl/D [124 m3/d] above pretreatment decline rates. Cost of the seven field tests (including well workover, gel, and gel injection costs) totaled $438,000, yielding a cost for incremental stock-tank oil production through May 1987 of $0.97/bbl [$6.10/m3). The field testing program has shown that the new gel CIT technology can generate significant amounts of incremental oil production profitably, even during times of depressed oil prices, and can be used to significantly reduce water/oil ratios (WORs). Field testing has also shown that the gel technology is operationally attractive. At all nine field tests, quality CrIII gel was made consistently and injected without encountering any significant operational, safety, or environmental problems. Little, or no, chromium was detected in associated produced fluids. As intended, significant reductions in injectivity occurred during all the injection-well field tests. The field tests demonstrated that large volumes of gel can be injected into the cited fractured Big Horn Basin reservoirs.
This paper, the second in a series, reports on field testing of a new and patented, Del conformance-improvement-treatment (CIT) technology. The aqueous gels are formed by crosslinking acrylamide polymers (polyacrylamide or partially hydrolyzed polyacrylamide) with a chromium(III) (CrIII) crosslinking agent. The first paper reported on laboratory testing and evaluation of the new gel technology, and presented a brief description of the chemistry of the new gel technology.
In this paper, results relating to the new gel technology are reported for the first nine field tests that were carried out as a joint effort between the Rocky fountain Region Production and the Exploration and Production Technology Organizations of Marathon Oil Company. The nine field tests were performed in Wyoming's Big Horn Basin in 1985 and 1986; and all involved fracture conformance problems.
The eighty mile [130 km] long Cedar Creek Anticline structure, trending from eastern Montana to south-western North Dakota, contains at least a dozen carbonate reservoirs at an average depth of 9000 feet [2745 m]. All of the major oil accumulations have been under waterflood, starting from the mid-1950's to the mid-1960's. These waterfloods are now reaching a mature stage.
Laboratory PVT, core flood studies, and field measurements of waterflood residual oil saturation indicated that there was potential for carbon dioxide floods in the Cedar Creek Anticline water-flood units. A three well carbon dioxide injectivity test was initiated in 1983 in the South Pine Field to define carbon dioxide injectivity and extent of tertiary oil mobilization for the important Red River U4 interval.
The test consisted of an injection well, a logging observation well, and a pressure/sampling observation well. The three bottom hole locations were within 90 feet [27.4 m] of each other. The injection sequence was to inject twelve percent brine, a carbon dioxide slug, then resume the twelve percent brine injection. Pressures were monitored continuously in the injection well, the pressure/ sampling observation well, and a passive offset well 650 feet [198 m] from the test location. Detailed surveillance of fluid movement in the test area was obtained by frequent monitor logging using compensated neutron, induction and gamma ray logs. A post-flood pressure core was cut to measure the oil saturation remaining after the carbon dioxide slug injection.
Analysis of pressure measurements indicate the observed carbon dioxide injectivity was approximately fourteen times that of the preflood brine. Log and core measured saturations show substantial desaturation of waterflood residual oil in the well swept areas of the test interval; mobilized tertiary oil was also produced at the pressure/production observation well, located 70 feet [21.3 m] from the injector. The detailed analysis of fluid movement during the test has been complicated by the heterogeneous nature of the test interval at the location of the pilot. Flow horizons within the U4 with permeability contrasts on the order of a factor of fifty have been identified through analysis of brine tracer and carbon dioxide encroachment data. Pressure transient data, thermal front arrival times, brine tracer data, carbon dioxide and follow-up brine encroachment data, and tertiary oil desaturation log and core measurements were analyzed to obtain an estimate of the values of parameters needed for estimation of full scale flood response.
The eighty mile [130 km] long Cedar Creek Anticline (CCA) structure, trending from eastern Montana to southwestern North Dakota, contains at least a dozen carbonate reservoirs at an average depth of 9000 feet [2745 m] (Fig. 1). The Anticline is asymmetric, with multiple faults bounding the west flank, where beds dip up to 15 degrees [0.262 rad]. On the east flank, large faults are uncommon and formations dip less than three degrees [0.052 rad]. Oil accumulations occur along the crest of the Anticline in rocks ranging in age from Mississippian to Ordovician. The major oil reservoirs are of Silurian and Ordovician age. The reservoirs are thin (less than 30 feet [9 m]) fine to extremely fine-crystalline dolomites. A typical type log for the Anticline is shown in Figure 2.
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: (a) to establish a valid baseline for injection and production before the treatments, (b) to hold injection in the surrounding patterns at or below pretreatment levels, in order to isolate the causes of any oil rate increase, and (c) 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.
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.
Dispersivity affects the displacement and sweep efficiencies and the required slug size of a displacing fluid. Unfortunately, the dispersivity values estimated from field tests are a few orders of magnitude greater than the values obtained in laboratory tests. This investigation studies the effect of small scale (or core scale) heterogeneities on the effective dispersivity value in a typical gridblock size used in a reservoir simulator. The study is restricted to contact miscible displacements with unit mobility ratio. A finite element simulator is used to investigate these effects. Physical dispersion is explicitly included in the simulator.
Results show that the effective dispersivity is affected by the degree of heterogeneity, the average length of heterogeneity, the length of the system, and the manner in which the permeability values are spatially distributed. The effect of heterogeneity becomes significant if the coefficient of variance is greater than 0.4. The effect of dimensionless scale length (ratio of average length of heterogeneity to length of the system) on effective dispersivity is insignificant for dimensionless scale values less than .01; above that value dispersivity increases with an increase in the scale length. The effective dispersivity increases almost linearly with an increase in the length of the system for constant dimensionless scale length. This provides an explanation for the similar trend reported for field dispersivity data. A simple correlation is proposed to calculate the effective dispersivity of the porous medium. The effect of the way in which given permeability values are distributed across the medium on the dispersivity cannot be correlated with the parameters investigated, probably indicating that the effective dispersivity is a unique function of the manner in which permeability values are distributed. This effect was not noted previously in the literature; however, it does not affect the general trends.
Dispersion is important in understanding reservoir performance during enhanced oil recovery processes. Large values of dispersivity reduce the displacement efficiency of multiple contact miscible displacements and increase the sweep efficiency. The net result of dispersion may be to increase the required slug size of a displacing fluid. Unfortunately, the values obtained in the laboratory do not coincide with the values obtained in the field. The reasons for the discrepancy between the field and the lab values may include the effects of heterogeneities in reservoir properties and reservoir stratification. This discrepancy should not arise if all the possible heterogeneities in the reservoir, including the small scale heterogeneities, can be described rigorously. However, this type of description may not be practical. Generally, a reservoir simulator gridblock is the smallest unit by which heterogeneities in the reservoir may be represented.
This investigation is restricted to study the effects of permeability variations in porous medium on the effective values of dispersivity. In cases studied, the permeability variations are the heterogeneities with length of variation about the same as that of the core length, (for example, several inches to several feet), sometimes called small scale heterogeneities. The effects of these small scale heterogeneities on the effective dispersivity value in a typical block size in a reservoir simulator are investigated. In other words, we are addressing the question of dispersivity scaling from laboratory to a typical block size in a field scale simulator. The studies are restricted to unit mobility ratio and contact miscible displacements.
BP Canada Inc, in partnership with Petro-Canada Inc., operates an in situ thermal project in the oil sand deposits of Cold Lake. Parts of the project area are underlain by a water-rich silt zone and a thin water sand which have the potential to limit bitumen production and increase water production. In order to minimize the water production, the operating strategy was optimized.
A detailed geological model of the oil sand-silt zone-water leg was prepared, and a numerical modelling study was initiated. The data were averaged for numerical modelling using a novel pseudoization procedure which maintained the important features of the oil sand-water leg interactions. Using the above technique, the numerical model reproduced the field performance accurately.
A pattern study was conducted to (1) duplicate field results and to (2) test several operating strategies. Analysis of the operating strategy indicated that a four well areal element could he used to model a sixteen well satellite.
The model developed was used to history match the bitumen and water production of the wells affected, using three different vertical representations. The models were subsequently used to investigate several operating strategies. Encouraging results were obtained, when the operating strategy recommended by this work was implemented in the field.
This paper describes the salient features of the pseudoization techniques used to develop the numerical model of the water leg reservoir, compares field and model results, and describes the, operating strategies investigated.
The wolf Lake lease is located in the Cold Lake oil Sand deposit in Northeastern Alberta, Canada; and is owned equally by BP Canada and Petro-Canada. The lease covers an area of 30,000 hectares (117 square miles); and contains an estimated 600 million Cubic metres (3.8 billion barrels of bitumen in place The Wolf Lake Project is one of the first commercial in situ oil sands projects in Canada.
Bitumen is recovered at the Wolf Lake Project using Cyclic Steam Stimulation, since the bitumen at reservoir temperature is too viscous to be produced by conventional methods. This process entails injecting high pressure steam into the formation for one to two months and producing the wells for six to twelve months. The process is repeated when bitumen production is deemed too low. This process is usually complicated by the presence of bottom water which can act as a thief zone for the steam.
Portions of this oil sand project, shown in Figure 1, are underlain by sand-silt oil-water transition zones and thin water legs. Initially, field operation indicated that these water-rich zones did not result in excessive water production. Therefore, they were largely ignored until one of the Wolf Lake pads, Q1, was put into operation. Q1 was perforated in a transition zone, in an area with bottom water. The increased water mobility in the transition zone caused producing wells to water out when adjacent to wells which were injecting steam.
It was apparent that the cyclic steam technology currently used at the Wolf Lake Project was unsuitable for this type of reservoir. Therefore it was imperative that a new operating developed for this reservoir.
This paper describes the steps that were taken in order to develop the new operating strategy for Q1 Pad. In particular, this work has:
1. Developed a consistent procedure for modelling transition zones and water legs.
A substantial increase in oil production resulting from CO2 flooding has been clearly identified in two multi-pattern areas of the SACROC Unit. Analysis of the two areas permitted the identification of oil response to CO2 injection with greater accuracy than has previously been possible at SACROC. The areas include the 600 acre [2.43 x 10 (6) m2] Four Pattern Area (4PA) and the 2700 acre [10.93 x 10 (6) m2) Seventeen Pattern Area (17PA). Located in the Kelly-Snyder Field of Scurry County, Texas, the 50,000 acre [202.3 x 10 (6) m2] SACROC Unit is the world's largest CO2 miscible flooding project.
The 4PA encompasses 24 wells arranged in four contiguous inverted 9-spot injection patterns. The area has been on pattern waterflood since 1972 and was at a 95 percent producing water cut when CO2 water-alternating-gas (WAG) injection was commenced in June 1981. An approximate 30% hydrocarbon pore volume (HPV) of CO2 was injected over a 5-year period at WAG ratios ranging from two to eight. CO2 injection ceased in May 1986 and the area has been on continuous water injection since that time. Incremental oil recovery attributable to CO2 injection is estimated currently to be at least 9% of the original oil in place (OOIP). This represents an estimated cumulative CO2 utilization of 9.5 Mft3 per barrel of incremental oil [1692 m3/m3].
Also on pattern waterflood since the early seventies, the Seventeen Pattern Area has exhibited an approximate 5% OOIP recovery after injecting 17% cumulative HPV CO2. CO2-WAG flooding in the 17PA began in May 1981. Currently, the cumulative CO2 utilization is estimated to be 9.7 Mft3 per barrel of incremental oil [1728 m3/m3].
This paper examines the methods used to determine CO2 mobilized oil response, describes how the effects of workovers and other "normal" field operations were accounted for, and evaluates the influence of activities in patterns adjacent to the study areas.
A substantial increase in oil production resulting from CO2 flooding has been clearly identified in two multi-pattern areas of the SACROC Unit. The intent of this paper is to document that response. CO2 performance reported herein is that which has been observed under "normal" field conditions and operations.
SACROC DESCRIPTION AND EARLY PROJECT PERFORMANCE
The SACROC Unit has been the subject of a great many papers dealing with the reservoir description, the CO2 displacement process, CO2 transmission, performance of the CO2 project, and many other topics. The history provided below, therefore, is only a synopsis.
Early History of the Kelly-Snyder Field
Discovered in 1948, the Kelly-Snyder Field is located in Scurry County, Texas (Fig. 1). The discovery well, Standard of Texas Brown 2-#1, was drilled to 6,700 feet [2042 m], 9 miles [14.5 km] northwest of Snyder, Texas. The well flowed 530 bbl/D [84.3 m3/d] from the Canyon Reef formation. Further development drilling proved up an area encompassing some 84,000 acres [340 x 10 (6) m2]. To date this discovery represents one of the last billion-plus barrel reservoirs to be found within the continental U.S.A. Pertinent reservoir data and properties are summarized in Table 1.
Several correlations have been proposed for prediction of three-phase relative permeability from two-phase data or from saturation/capillary-pressure relationships. These include the models of Stone, Hirasaki, Corey et al., Naar and Wygal, Land, Aleman, and Parker et al. This paper compares predictions of these models with predictions of two additional models (saturation-weighted interpolation and true-linear interpolation). The comparison is made using all the published three-phase experimental relative permeability data complete enough for application of the models.
The comparison shows that the models are often not very good predictors of the experimental data. This points out a need for better relative permeability models in cases where three-phase flow may have a significant effect. In most cases, straight-line interpolation or saturation-weighted interpolation between the permeabilities at the two-phase boundaries of the three-phase flow region provided a better fit of the experimental data than did the theoretically-based models.
The paper also demonstrates the utility of comparing the effects of different relative permeability models before using them in a reservoir simulation. Sometimes the result of a simulation can be heavily biased by the choice of relative permeability model used.
Three-phase relative permeability measurements and correlation methods have been reported in the literature since 1941. This paper lists the sources of published three-phase relative permeability data and compares the simple correlation methods which have been proposed for prediction of three-phase relative permeability. Two additional interpolation methods are proposed and compared to the published methods.
Data Sources for Three-Phase Relative Permeability
Three-phase (gas/oil/water) relative permeability data for water-wet sandpacks have been reported by Leverett and Lewis, Reid, Hosain, Snell and Ivanov. Three-phase data for water-wet cores have been reported by Caudle, et al. Corey, et al. Sarem, Donaldson and Dean, Saraf, Juckert; Saraf et al., van Spronsen, Holmgren and Morse, Slack and Ehrlich and Schneider and Owens. Very limited three-phase data for oil-wet cores (gas and water relative permeabilities at constant, non-flowing oil saturation) were published by Schneider and Owens. Descriptions of the test procedures and calculation methods are available in the original references. Donaldson and Kayser provide a summary of the test protocols and results for most of the data published prior to 1980.
The data for water-wet cores and for sandpacks show generally consistent behavior; isoperms (contours of constant phase relative permeability) for gas and water primarily depend on the gas or water saturation respectively, and are weak functions of the saturations of other phases present. The permeability to each phase is clearly affected by the saturation history when there is hysteresis between the inhibition and drainage curves for that phase. These data indicate that a strongly wetting phase (water) and a non-wetting phase (gas) are affected little by interactions with other phases (except for the physical obstruction caused by the presence of the other phases). An intermediate wetting phase (oil) appears to be more influenced by interactions with the other phases. The nature of the inter action is not clear, however.
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.
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%.