This paper presents experimental and simulated results from two vertical core floods. The core floods consisted of injecting equilibrium gas and separator gas from the top of the core after water flooding from the bottom, respectively.
The results show that an oil bank was formed in both experiments. When separator gas was injected, oil was also recovered by vaporization.
Compositional analysis of the produced fluids during separator gas injection shows that considerable amounts of intermediate components were produced as condensate after gas breakthrough. Significant end effects were observed in the final water saturation profiles due to capillary hold-up. Analysis of the final oil saturation in the core indicates a significant gradient due to vaporization, and greater than that modeled by the compositional simulator based on an equation of state.
Water injection into sandstone oil reservoirs may achieve high sweep efficiencies. However, considerable quantities of oil will still remain in a reservoir at the end of a successful water flood, with typically more than 50% of the original oil in place. This residual oil is a target for gas flooding after water flooding, termed here as tertiary gas injection.
Gas injection may recover additional oil because of lower residual oil saturation after gas flooding, typically 5% to 30%. During gas flooding, the oil saturation is reduced due to convective flow and mass exchange between oil and gas.
Besides improving microscopic sweep efficiency, tertiary gas injection may reach regions of a reservoir not swept by water, for example "attic oil." The situation is, however, more often one in which the sweep efficiency is low for tertiary gas injection, a general problem associated with injecting gas. Some means of controlling gas mobility may therefore be aimed at, such as gravity stable gas injection or water alternating gas injection.
During tertiary gas injection, large quantities of mobile water are present in the porous medium, causing a long period of water production prior to the arrival of the oil bank at the producers.
Tertiary gas injection introduces conditions for three phase flow. In parts of the reservoir, three phases may be flowing simultaneously, or oil and gas may flow through paths of water saturations different from connate. This implies that the process may be situated in the three phase space at positions different from those where the relative permeabilities are usually measured. Correlations have been introduced in order to estimate oil relative permeability in the three phase mode from measured two phase data to be applied in reservoir simulators. The correlations are introduced because these quantities are not easily accessible experimentally.
High water saturations in the porous medium nay also influence the mass exchange between gas and oil, and thus modify the process efficiency in an unfavorable way.
This paper presents the results of an extensive study aimed at describing the viscoelastic properties of polymer solutions for enhanced oil recovery. Using natural and artificial cores and polymer solutions with different storage factors, core floods were performed to examine the influence of viscoelasticity of polymer solutions oil flow behaviour and oil recovery.
From the experimental results, it appears that beyond a critical injection rate the viscoelasticity of polymer solutions is reflected by increasing of effective viscosity. This critical injection rate is dependent on the concentration and degree of hydrolization (HPAA), molecular weight of polymers, core permeability, salinity and temperature. Therefore the viscoelastic core flow behaviour of polymer solutions can be adjusted to specific reservoir conditions by variation and optimization of these parameters.
To describe and quantify the viscoelastic effects by means of experimental results, a model based on Maxwell-Fluid-Relation is applied. Using the proposed model, the model index E can be, determined, which represents the viscoelastic behaviour of polymer solutions in porous media. It is found that not the relaxation time, but the model index E is the parameter which should used for quantifing this viscoelastic behaviour of polymer solutions in porous media.
The flow behaviour of polymer solutions in porous media can be explained by two distinct processes: Shear flow and Strain flow. Accordingly the effective viscosity of the solution ( ) is composed of the individual contributions of shear - ( ) and strain ( ) viscosity.
As long as the molecules of the polymer are able to rotate in the volume, of the, pore while flowing through it, the molecules will not be strained and the effective viscosity is caused by shear flow alone. If the period under strain during rotationless flow is long enough, a deformation of the polymer molecules is possible under certain pore geometries. This deformation will cause an increase in strain viscosity and therefore results in an overall increase in the effective viscosity.
Laboratory studies were conducted to find the best surfactant for generating CO2 foam in the presence of residual oil for two dolomite reservoirs. Conventional anionic and nonionic surfactants did not foam very well in core tests at reservoir conditions. The poor performance was attributed to the oil-wet nature of the dolomite cores. A new surfactant formulation was developed that alters wettability and has much better oil tolerance. CO2 foams were generated easily with the new formulation and were more stable. Field tests are planned to demonstrate improvement of sweep efficiency using the new surfactant.
Evaluation of surfactants for mobility control applications involved a series of tests that measured brine compatibility, bench foam height, flow resistance in corefloods, and adsorption on reservoir rock. Bench foam tests, often used for surfactant screening, were unable to predict the effects of oil in the corefloods. Even the low oil saturation remaining after immiscible or miscible CO2 injection was detrimental to foam generation. The new surfactant formulation works over a wide range of brine salinities, controls CO2 mobility better than conventional surfactants, and has moderately low adsorption on dolomite rock.
Oil production from CO2 flooding is increasing steadily in the U.S. despite marginal oil prices. There are many field-wide projects under way in West Texas, and new projects are planned for the mid-90's. CO2 is injected continuously or alternated with water if there is channeling and gravity override. The need for better CO2 mobility control grows as the older projects mature because of declining oil production and increasing CO2 recycling costs. The use of foam-forming surfactants to improve sweep efficiency and reduce CO2 breakthrough has received extensive laboratory evaluation but only limited field testing with mixed results. A large field demonstration of CO2 foam is planned for 1992 that should define better the potential of this promising technology.
This paper describes the evaluation of foam-forming surfactants for two dolomite reservoir applications. The objective for Reservoir A was to find a suitable surfactant to improve the performance of immiscible cyclic CO2 treatments. For Reservoir B, surfactant would be used in a CO2 drive to improve the injection profile and control in-depth CO2 mobility under miscible conditions. Both reservoirs are challenging applications for foam because the dolomite rock tends to be oil-wet, which inhibits in-situ foam generation. Residual oil saturations are higher in Reservoir A than in Reservoir B because the CO2 is injected well below the minimum miscibility pressure.
Our strategy in evaluating surfactants was to select a few commercial products that were identified previously as good foaming agents. These products were passed through a series of screening tests that measured brine compatibility, bench foam height, adsorption on reservoir rock, and foam performance in corefloods at reservoir conditions. The corefloods were a critical part of our evaluation because they modeled reservoir behavior more accurately than bulk foam, glass bead pack, or sand pack tests.
The spreading characteristics of a gas/oil/surfactant solution system depend on the interfacial tensions involved. This work indicates that systems having interfacial tensions giving spreading oil act more deleterious to foam stability as compared to nonspreading oil systems. The effect was demonstrated for Berea sandstone by changing the oil when the type of surfactant was unaltered and by changing the type of surfactant when the oil used was the same. For a slightly oil-wet reservoir rock a similar trend in foam properties was observed when the type of oil was changed.
In an oil spreading system the flow resistance of foam was found to increase with increasing concentration of the surfactant solution.
The concept of using foam to reduce gas mobility was initially patented by Bond and Holbrook in 1958.
Foam may be utilised for different purposes in a reservoir situation, either for zone blockage or for mobility control of gas. The former needs a strong and viscous foam, whereas the latter requires a less rigid foam.
Several successful foam injection projects have been performed. The purpose has mainly been gas diversion and blocking of high permeable streaks. However, minor experience exists on the use of foam for mobility control, a situation where foam has to propagate throughout the whole reservoir.
Influence of Oil on Foam Stability
The presence of oil in porous media is generally known to decrease the mobility reduction of gas obtained by foam. This has obviously implications for the use of foam in improved oil recovery. Several mechanisms have been suggested in order to explain the effect of oil on foam properties.
Much attention has been paid to effects related to the surface energies involved in the gas/oil/surfactant solution system. Lau and O'Briens and Kuhlman have indicated that spreading of oil on foam bubbles or lamellas decreases the stability of foam. Oil spreading may cause film thinning below a critical limit for mechanical stability, and the lamella breaks. Manlowe and Radke, however, have suggested that spreading of oil on foam lamella is not critical. Rather, the so-called "pseudoemulsion-film" governs the foam stability. This film is formed whenever foam bubbles or lamellas contact oil.
Schramm et al. bring the lamella number, L , and the entering coefficient, E, into a phenomenological theory for the effect of oil. If L is greater than one, small oil droplets will be sucked into the Plateau borders of foam lamellas due to the low hydrostatic pressure in this region. If E is greater than zero, the oil droplet will enter the lamella surface. If, further, the spreading coefficient for the oil, S , is positive, the oil will spread over the surfactant solution surface. This may lead to lamella rupture. If both E and S are negative, oil will neither enter the lamella/gas interface or spread over it. This is the situation where the presence of oil is believed to have the least deleterious effect on foam stability.
Pilot in-situ combustion oil recovery operations began in the South Belridge Field in 1963, and commercial operations began on a 164-acre area in 1964. This operation ended in 1986 when an air compressor failed. South Belridge oil In place of a third of billion barrels of oil with an estimated 8 percent recovery inspired interest in thermal oil recovery in 1947. This study presents results of 22 years of commercial in-situ combustion at South Belridge.
Although continuous steam injection is the most important thermal oil recovery operation in South Belridge, in-situ combustion offers opportunity for extending thermal operations in other fields far beyond bounds appropriate for steam injection. Results at South Belridge for both commercial steam injection and in-situ combustion have been published. Steam injection Is among the best in California, and in-situ combustion is considered average for California conditions.
At South Belridge, the surface energy requirement per barrel of oil produced by insitu combustion was about one fifth that required for steam drive. The pounds of flue gas generated per barrel of oil recovery from in-situ combustion was about half that required for steam drive. Emulsions were produced by in-situ combustion, but posed no special problems. Well failures for in-situ combustion were similar to those for steam drive once old (pre-1964) completions were replaced.
The ratio of cum. inj. air to cum. prod. oil was 3.7 MCF/BBL, about a third of the design ratio. In-situ combustion offers an efficient extension of thermal enhanced oil recovery to deep, high-pressure, low-oil-reactivity formations.
A letter from H.N.Marsh to R.O.Swayze of The General Petroleum Corporation (Mobil Oil) dated April 16, 1947 estimated original oil in place in the South Belridge Field at a third of a billion barrels and ultimate recovery as 8%. He described a conference In their Bakersfield office at which "ideas which may be fantastic were encouraged". of the many ideas considered at that meeting, application of heat by combustion appeared promising and Marsh wrote "it is proposed to request the Dallas Laboratory to give some theoretical study to the economics of underground combustion". R.O.Swayze forwarded Marsh's letter to M.S.App, Director of Production, with the interesting comment "Marsh and I had under consideration a scheme to drill a well on Moco 34 and when the oil zone was encountered, drift the hole at a fairly flat angle parallel to the bedding in the oil zone ... "
By 1954, many laboratory and two small-scale field tests of in-situ combustion indicated promise, and a 2.5-acre isolated pilot test was started In 1956 in Section 10 of the South Belridge Field in the Tulare formation. This project was supported by 12 oil companies and results through 1957 were presented by Gates and Ramey . In-situ combustion continued through 1959. Results through 1959 were presented by Gates, et al. in 1978.
This paper summarizes the results Of field application of EOR techniques in the former Soviet Union. 175,000 barrels of incremental oil per day were produced in 1991 due to their implementation in different geological and environmental conditions. 55% of total production or 96,500 BOPD were produced with the application of chemical methods, 64,500 BPD or 37% were produced due to thermal and the rest - due to gas injection methods. The hydrodynamic improved oil recovery methods based on waterflooding technique and reservoir management brought another 600,000 BPD additional oil. The future of enhanced oil production depends on wide application of both conventional and nonconventional advanced methods tested in laboratories and in field sites and provided for their high efficiency.
The outlook of wide application of EOR and IOR techniques by the years 2000 and 2010 at different economical conditions is presented.
Oil production in the former Soviet Union after many years of sharp increase started to decline. In 1991 our country produced 10.4 MM BOPD, 17% less than in 1987 and 1988 when the maximum oil production level of 12.5 MM BPD was reached.
EOR and IOR techniques are considered to be an important tool to stabilize domestic oil production or reduce the rate of its decline.
All known conventional EOR methods widely apply in different geological and environmental conditions.
Thermal oil recovery was first started in 1966, in Trintopec's operations, with a small cyclic pilot project in the Palo Seco field. Twenty-five (25) years of thermal recovery, comprising cyclic and flood operations, have witnessed vigorous growth and dynamic expansion to the extent that, by 1991, the thermal recovery statistics are as follows :
(a) Steamflood operations exist in all the Company's major land fields, viz., Palo Seco, Central Los Bajos, Guapo, North Fyzabad and Apex-Quarry/Coora/Quarry.
(b) Total production from thermal recovery averages 9100 bopd, representing 55% of Trintopec's current land production.
(c) A total of approximately 40000 bspd is being supplied by 23 steam generators to more than 150 steam injectors.
This paper presents highlights of Trintopec's experiences in the design, implementation and operation of thermal oil recovery schemes. New concepts, innovations, modelling and monitoring techniques over the past twenty-five (25) years are outlined, and, in addition, projections for the future are indicated.
Of the enhanced oil recovery techniques available to the industry, viz., thermal (steam and in-situ combustion), miscible, chemical and polymer floods, the single method that has attained most widespread acceptance has been the use of steam, both in cyclic and flood-type operations.
Not surprisingly, this method has manifested itself as the major thrust of EOR operations at Trintopec. The primary factors that motivate its use are as follows
(i) Cost effectiveness, with water being cheap and readily available,
(ii) Abundance of heavy oil reserves in Trintopec's leases,
(iii) Projected recovery of lighter oil, by distillation,
(iv) Proven success of method, both internationally and at Trintopec.
Significantly, and expectedly, the growth of associated technology in the Company's thermal operations has paralleled the increased production rates from thermal operations. Although the current performance of the Company's thermal schemes is such that 55% of land production is thereby accrued, and prospects for further enhancement of thermal production are encouraging, it would be erroneous to suggest that the path was not fraught with difficulties and operational problems. Nevertheless, through a vigorous and dynamic growth and expansion programme, the method employed in the thermal recovery schemes, although not fully state of the art, have been refined to the point of acceptable confidence levels. Trintopec then, continues to maintain its pioneering status in thermal recovery in Trinidad and Tobago.
Martin, F.D. (New Mexico Petroleum Recovery Research Center) | Heller, J.P. (New Mexico Petroleum Recovery Research Center) | Weiss, W.W. (New Mexico Petroleum Recovery Research Center) | Tsau, Jyun-Syung (New Mexico Petroleum Recovery Research Center) | Zornes, D.R. (Phillips Petroleum Co.) | Sugg, L.A. (Phillips Petroleum Co.) | Stevens, J.E. (Phillips Petroleum Co.) | Kim, J.E. (Phillips Petroleum Co.)
The East Vacuum Grayburg/San Andres Unit (EVGSAU), operated by Phillips Petroleum Company, is the site selected for a comprehensive evaluation of the use of foam for improving the effectiveness of a CO2 flood. The four-year project is jointly funded by the EVGSAU Working Interest Owners (WIO), the U.S. Department of Energy (DOE), and the State of New Mexico. The Petroleum Recovery Research Center (PRRC), a division of the New Mexico Institute of Mining and Technology (NMIMT), is providing laboratory and research support for the project. A Joint Project Advisory Team (JPAT) composed of technical representatives from numerous major oil companies provides input, review, and guidance for the project.
The EVGSAU, located about 15 miles northwest of Hobbs in Lea County, is the site of the first full-scale miscible carbon dioxide injection project in the state of New Mexico. The 5000 acre CO. project is divided into three water-alternating-gas (WAG) areas where CO2 injection was initiated in September of 1985. A 2:1 WAG ratio was chosen so that while CO2 is injected into one area, water is injected into the other two areas of approximately equal pore volumes. After each fourth month of operation, CO2 injection is rotated into another WAG area.
While tertiary oil response at the EVGSAU is very favorable, some wells are showing excessive CO2 breakthrough, thereby increasing CO2 recycling and compression costs. This project includes a field demonstration of the use of foam to reduce the mobility of the injected CO2, reduce excessive CO2 production, improve the volumetric sweep efficiency of the injected CO2, and increase the incremental oil recovery from the tertiary project. Thus, a suitable pattern in the EVGSAU was selected, based on the criterion that the production there be typical of other patterns without a distinctly better or worse record of CO2 breakthrough than in the rest of the field. An observation well was drilled in the pattern; location of this well is approximately 150 ft from the pattern injection well, The observation well was cored and logged to improve reservoir characterization in the pattern area, as well as to provide reservoir cores for laboratory tests with suitable foam-generating surfactants. In order to use the borehole as a logging monitor well, the bottom 800 ft was cased with fiberglass.
The objective of this four-year project is to conduct reservoir studies, laboratory tests, simulation runs, and field tests to evaluate the use of foam for mobility control or fluid diversion in a CO2 flood. A geological characterization of the pilot area and surrounding patterns has been assembled for the history matching and reservoir simulation studies that are in progress. The foam-flood mechanistic model developed at the PRRC is being incorporated into the field-scale reservoir simulator.
This paper summarizes the project plans, the baseline field testing, and the laboratory test results that pertain to surfactant selection. This overview provides a background for subsequent papers that will report on various aspects of the project.
The use of CO2 as a displacement fluid during enhanced recovery processes has increased in recent years, and work involving the selection and development of mobility control additives for use in CO2 flooding has gained importance. Several organizations have been working on processes to improve the efficiency of CO2 displacements that consist of the injection of a mixture of dense CO2 with an aqueous solution of a suitable surfactant. This mixture generates lamellae (bubble films) in the pore space of the rock which allows the mixture to move through the rock with a mobility that is significantly lower than that of CO2 alone. The CO2-foam that is generated can also reduce the nonuniformities of the displacement front that are otherwise induced by now through the heterogeneities of the rock. Thus, the use of CO2-foam as a displacement fluid can give two benefits over the use of CO2 alone: it can reduce or suppress the formation of fingers caused by the instability of the displacement front, and it can reduce the severity of channels or preferential now that would otherwise occur because of heterogeneity of the reservoir rock.
For several years, laboratory work has been conducted at the Petroleum Recovery Research Center (PRRC), a division of New Mexico Institute of Mining and Technology (NMIMT), on the use of surfactants to generate foam for increasing the efficiency of CO2 floods.
The paper represents, mainly, a review on the state of the art concerning the suitable bacterial inoculum used during the last 15 years in the field trials carried out in Romanian's oil fields. The experience accumulated during the last 35 years, mainly in countries as USA, Russia, Cechoslovakia, Hungary, Poland, Germany, Romania, China, Canada, Australia and Great Britain proved that the bacterial inoculum is one of the basic components for the success of the MEOR method. It was also, already proved that the MEOR method from the technological point of view has a few possibilities of application in the field literature as: 1) microbial wellbore cleanup; 2) microbial well stimulation; 3) microbial enhanced waterflooding; 4) microbial permeability modification; 5) microbial polymer flooding; 6) microbial mitigation of wellbore; 7) activation of the strata and injection water microflora. In addition to these technologies of MEOR method, a few other could beadded as: Microbial Fracturing fluids Recovery, Microbial Paraffin Removal Treatment, etc, but the above ones seems to be most representative and already proved to be of future.
In Romania during the period 1971-1991 the laboratory and field activity on MEOR method carried out without any interruption. In the laboratory the activity was much more complex, and continuously, while in the field in two periods (1975-1980 and 1986-1990) were carried out field trials, using the technologies mentioned above that ones nominated at points 1, 2 and 3. In framework of these technologies it was used generally the same kind of bacterial inoculum namely: "Adapted Mixed Enrichment Cultures" (AMEC), which proved to have a very good growth under reservoir conditions with temperatures up to 55C, salinity up to 100-150 g/l, deepness up to 1000-1500 m and oil viscosity up to 50. During the last two years it was concluded that a mobile unit or a special equipment with all the technical facilities for isolation, adaptation, characterisation and multiplication of such a bacterial inoculum - straight in the field, is very necessary. Such kind of equipment was recently designed in Romania, and is recommended to be used in future.
The world petroleum crisis which came about twenty years ago have determinated an increase of the interest for development of the modern methods,? for increased oil recovery including first the physical and chemical methods. Along with this methods the interest increased year by year also for other methods as the microbiological one. Although the microbiological method appeared as an ideas with more then 65 years ago and have been scientifically developed in the period 1943 - 1955, it started to be tested in the field after 1957, so at the moment of petroleum crisis, namely 1973, it was very little known for the oil industry.
The technical performances of horizontal and vertical wells were examined for a tertiary, carbon dioxide miscible flood in a 240-acre (97 ha) area of and west Texas field using a black-oil, pseudo-miscible simulator. Although and 4D acre (16 ha), inverted fivespot pattern was used initially for both vertical and horizontal wells, the spacing was increased to 60 acres (32 ha) for the horizontal wells to maintain the miscibility pressure in the reservoir. Horizontal injection and production wells, 1,320 feet (402 m) in length, completed at the bottom of the formation, recovered 14 to 22 percent more oil than vertical wells. Economic analyses for the horizontal injectors and producers were compared to economic analyses conducted for vertical injectors and producers. Project economics were significantly affected by the capital expense for drilling new wells. The vertical wells provided the better rate of return if no now drilling or only one now well for every six patterns was required. If horizontal wells could be drilled from existing vertical wells or from the surface at 1.5 times the cost of vertical wells, the rate of return was comparable or better than vertical wells requiring one new well for every three patterns. Horizontal wells drilled from the surface at twice the cost of vertical wells provided the lowest rate of return.