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.
To assess the economic viability of a proposed polymer augmented waterflood and to design the treatment, it is necessary to determine the polymer retention level in the rock matrix.
Static adsorption experiments on rock samples are unsuitable, because the crushing process may expose new sites, and mechanical entrapment of molecules in pores is not included in the measurements. Dynamic core-flooding measurements, at deep reservoir flow rates, are therefore required. However, reservoir core plugs may be contaminated by drilling muds, particularly at the ends, increasing the adsorption capacity. In this case, detailed mass balance calculations on the polymer effluent profiles may significantly overestimate retention levels in the formation.
To overcome these problems, a pyrolysis/beta scintillation counting technique has been developed. The core plug is flooded with 14 C-labelled polymer. It is then disassembled and samples from the interior are crushed and pyrolysed, to convert the carbon to CO2. The 4C content of the gas is measured via beta-scintillation counting, giving the polymer retention level in the plug's interior, where face filtration and drilling mud contamination are minimised.
This paper describes the validation of the technique. The reproducibility and efficiency of the recovery are shown to be independent of the crushed particle size, over the range 50-1000 um, the polymer retention level, over the range 1-120 ug/g, and the presence of oil at residual saturation. Finally, the retention levels deduced from a detailed mass balance calculation and subsequent pyrolysis/beta scintillation counting of samples from an uncontaminated core are compared, and found to be consistent.
This technique is recommended for the determination of polymer retention levels in the rock matrix, under as near as possible reservoir conditions, assuming that a small amount of C-labelled polymer is available.
To design a polymer project and assess its economic viability, it is necessary to estimate the polymer retention level in the native rock at deep reservoir flow rates. The retention may include chemical adsorption onto clays or rock surface adsorption sites and mechanical or Hydrodynamic entrapment of the molecules in pore throat constrictions and dead-end spaces.
Static adsorption experiments on crushed rock samples are unsuitable for estimating the retention level for two reasons. Firstly, dynamic effects, such as mechanical and hydrodynamic entrapment in pore spaces, are not included in the measurement Secondly, new adsorption sites may be exposed and activated in the crushing process, resulting in an overestimate of the adsorption capacity of the consolidated rock.
The effluent profiles from core-flooding experiments at appropriate flow rates can be analysed to obtain dynamic retention levels for the core sample, via a detailed mass balance calculation. However, the core sample may not be representative of the native rock in the formation.
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.
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 dynamic adsorption and in situ rheological behaviour of xanthan biopolymer flowing through porous media have been investigated. Results are related to the depleted layer effect, where polymer/pore wall interaction due to steric hindrance leads to a lower Newtonian apparent viscosity than bulk Newtonian viscosity. Previous work on the depleted layer phenomenon has been presented considering the effects of polymer concentration over the very dilute regime, pH and salinity on xanthan rheological and transport behaviour in porous media. Experimentally, the apparent viscosities of xanthan solution flowing in the ballotini glass bead packed columns were measured under various conditions and compared with the corresponding bulk viscosities. The experimental data were analysed using simple analytical models (two-fluid model and linear layer model) in order to estimate the apparent depleted layer thickness. The results presented in this paper extend some of our earlier findings on the effect of both polymer concentration and salinity on the apparent depleted layer thickness. The main new results presented in this work concern the effect of xanthan dynamic adsorption on the in situ polymer rheology and depleted layer thickness. The depleted layer effect is measurable both before and after dynamic adsorption has reached equilibrium. However, the additional effect of the adsorbed layer close to the pore wall is small indicating that xanthan molecules are adsorbed very flat against the pore wall.
The adsorption and the in situ (porous medium) rheology of xanthan have been studied by a number of workers due to the importance of this biopolymer in enhanced oil recovery processes. The level of xanthan adsorption (or retention) is one of the key factors in determining the economic viability of a polymer flood using this biopolymer. In this work, however, we focus more on the effect of the dynamic adsorption level of xanthan on the in situ rheological behaviour during flow through porous media. One very interesting aspect of the in situ rheology of this biopolymer is that, under certain circumstance, an apparent slip effect is observed where the low flow Newtonian viscosity may be below the bulk fluid viscosity . This finding has been interpreted in terms of a depleted layer/surface exclusion phenomenon where the macromolecules are excluded from a zone close to the pore wall due to steric hindrance effects. Such effects on polymer flow in porous media were first reported by Chauveteau and coworkers and in a number of papers since that time. Many other workers have not found this type of behaviour, but this may be due to certain aspects of the solution preparation. At this laboratory, we have had no difficulty in reproducing the apparent slip effects arising from surface exclusion phenomena when the appropriate experimental precautions have been taken.
In previous studies , we have extended the results and findings of Chauveteau and coworkers in two ways.
Early water breakthrough can be a serious problem during waterflooding of heterogeneous reservoir formations. One possible remedy to this problem is to place a gel block in the high-permeability layer, thus diverting displacing brine into the less-permeable layers in order to sweep the remaining oil from these zones. In such a treatment, the gelant material must be placed in the correct location within the reservoir so that gel does not impair reservoir performance. In this paper, we study the dynamics of gel placement in heterogeneous (stratified) reservoir systems. The details of the gel placement are strongly affected by the level of communication between reservoir layers, which is characterized by the closeness of the system to vertical equilibrium (VE) conditions. We show that in viscous-stable injection of gelant in systems close to vertical equilibrium, considerable volumes of injected material can crossflow into the low-permeability layers, and subsequent gel formation can seriously reduce the performance of the continuing waterflood. Results from a range of experimental displacements in well characterized layered beadpacks are presented, along with supporting numerical simulations, which help to understand the mechanisms and benefits when performing gel treatments in reservoir systems with free crossflow. The central role of viscous crossflow in such systems is demonstrated. Since we consider only viscous forces in this work, the layered experimental packs are scaled only by the viscosity ratio (displacing to displaced), the geometry of the packs, the aspect ratio and the degree of vertical communication (closeness to VE). Thus the conclusions from the experimental and simulation results are directly applicable to similarly scaled viscous-dominated systems at the reservoir scale. Some analysis is also presented of the mechanism of disruption of slugs by viscous fingering in layered systems.
The objective of gel treatments in injection wells is to reduce flow through fractures or high-permeability zones while diverting injected fluids into hydrocarbon-bearing strata. In oil production wells, the main objective of gel treatments is to reduce water production without significantly reducing oil production. Achieving these objectives may be impeded by the formation of gel material in less-permeable, oil-productive zones. If gel treatments are to improve sweep efficiency, a pathway must be available between the wellbore and mobile oil in the formation. This can sometimes be accomplished by mechanically isolating zones during the gel treatment. However, zone isolation will not be effective if extensive crossflow can occur between reservoir layers of contrasting permeability (or possibly, if flow can occur behind pipe).
Much of the previous work concerning gel placement has focused on gel treatments in reservoirs with no communication between zones.
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.
It has been well documented that tertiary carbon dioxide WAG cycle injectivity during displacements above the minimum pressure for dynamic miscibility cannot be reliably predicted on the basis of viscosity ratios and waterflood injectivity performance alone. Approximate analytical models based upon gravity-free displacement with nondispersive plug flow of constant composition slugs in noncommunicating radial layers have been used to interpret injectivity during reservoir tests as a function of relative permeability, flow geometry, effective wellbore radius, and layering. We examine compositional simulation as an alternative for incorporating the additional effects of phase behavior, dispersive mixing, gravity, capillary forces. viscous instability, crossflow, and more realistic representations of reservoir heterogeneity in injectivity calculations for field test interpretation. We show how simple modifications can be made to an existing finite-difference equation-of-state simulator to allow for detailed modeling with these mechanisms of reservoir-scale cross-sections that incorporate geostatistical representations of reservoir heterogeneity and radial flow near injection and production wells. The compositional model is applied to simulate and interpret an injectivity test conducted in the Mabee Field in the San Andres Formation, Martin County, Texas. Injectivity during the field test was significantly greater than initial waterflood injectivity during all WAG cycles, increased during each CO2 cycle, and was greater than would be anticipated from other field tests in the San Andres formation or from available laboratory data. Compositional simulation of the field test indicates that the reservoir response during the first cycles of CO2 and brine injection, including the initial increasing CO2 injectivity trend and higher brine injectivity after the first CO2 cycle, are consistent with measured relative permeability, phase behavior, and reservoir characterization data, but that the observed injectivity increase during the second cycle Of CO2 injection cannot be attributed to either the near-wellbore condition of the reservoir at the start of the test or to the presence of thief zones that are statistically consistent with measured core data and well logs. Injectivity is a key variable in determining the economic incentive associated with a proposed CO2 project, and an important implication of this study is the validation of compositional simulation as a means for interpreting field tests and developing improved predictions of reservoir injectivity performance. Another important conclusion is that geostadstical techniques can be used successfully to characterize high heterogeneity in carbonate reservoirs for injectivity calculations.
The J.E. Mabee Field in the San Andres Formation, Martin County, Texas. is a candidate for tertiary recovery by multiple-contact miscible (MCM) displacement with carbon dioxide.
Shell Western E and P Inc. has been operating the Denver Unit CO2 flood, the world's largest CO2 enhanced oil recovery project, since 1983. The unit is in the Wasson Field in Gaines and Yoakum Counties in West Texas. While operating the flood, SWEPI has developed successful technology and operating methods for carbon dioxide flooding.
The paper is structured in three parts: 1) physical properties of CO2 , 2) physical effects of CO2 and 3) relative economic considerations associated with CO2. Operational considerations associated with each topic are identified and SWEPI's resulting modifications in operating policy are discussed. Some of the topics included in the paper are equipment and materials, artificial lift, well control, wellbore impairment, injection surveillance, and operations in a populated area. Discussions also include issues where our operating experience has varied significantly from our original expectations. These include the lower than expected corrosion rate of materials, and the higher than expected number of wells that flow naturally.
This overview will be of interest to companies who are either operating or preparing to implement CO2 floods. It will also interest service companies who may have or wish to develop products to service CO2 operations.
The Denver Unit is located on the southern edge of the North Basin Platform of the Permian Basin in far West Texas (Figure 1). The San Andres reservoir at the Denver Unit is a dolomite formation existing 4700 to 5100 feet below the surface (Table 1). The oil accumulation is controlled by its anticlinal structure. The Denver Unit contains both gas-oil and oil-water contacts. The reservoir is subdivided vertically into "First Porosity" and "Main Pay" zones, with the Main Pay containing the better quality reservoir rock (Figure 2).
Primary depletion drive production began in 1936 with single well production rates in excess of 1500 barrels of oil per day being common. In 1964, the Denver Unit was formed and waterflooding began. Carbon dioxide (CO2) injection began in 1983 when 9 inverted nine-spot patterns were placed on CO2 injection. Today over 500 million cubic feet per day (200,000 reservoir barrels per day) of CO2 are injected in 185 injectors (Figure 3). Daily production in 1991 averaged 37,000 barrels of oil and 36 MMCF of gas per day.
PHYSICAL PROPERTIES OF CO2 AND ASSOCIATED IMPACT
At the Denver Unit, CO2 is injected as a supercritical fluid at a surface pressure of about 1800 psi and a reservoir pressure of about 2200 psi (Figure 4). The critical pressure of CO2 is 1071 psi and the critical temperature is 87.9 F. Above these critical points, CO2 behaves as a vapor whose density increases as pressure increases. Below these critical points, CO2 may exist as a gas or a liquid.