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Results
Abstract Several properties of two of the viscous polymer fluids used in rheological control were investigated. Polymer adsorption on the rock surfaces of porous sand stones and its effect on permeability of producing formation was studied. permeability of producing formation was studied. A naturally occurring polymer, a Guar gum, was found greatly to reduce the permeability of the producing formation, although the use of a breaker solution was found to restore the permeability lost through polymer plugging. Use of appropriate breaker solution was found to reduce the loss permeability to only one or two per cent of the original value. Adsorption of the synthetic polymer, acrylamide, was found to be directly related to the shaliness of the porous sand. Deactivation of polymer due to adsorption was found to be significant in formations having large surface areas. The results indicate that polymer loss eventually results in a water bank ahead of the polymer solution and thus greatly reduces the polymer's effectiveness in water-flooding. Introduction Recently a great deal of interest has been shown in the use of polymer solution for secondary and tertiary recovery. For the present study polymers were added to water injected for present study polymers were added to water injected for water-flooding to improve the mobility between the injected fluid and the crude oil. Laboratory studies have shown that the injection of polymer solutions increased water viscosity and consequently reduced its mobility. The previous work has shown that use of certain naturally occurring and synthetic polymer was not successful in recovery process because of high polymer losses. The effect of two polymers, one a naturally occurring galactomannin (Guar gum) and the other a synthetic acrylamide, on water-flooding was investigated. The first type has been recommended and used for many years as a completion-and-workover fluid, and the second type for improving water-flood mobility by industry. This research was designed to determine polymer loss due to adsorption on rock surfaces. The adsorption has been attributed to grain-size sand and to the presence of clay minerals in the porous media. Control of polymer loss is one of the single most important factors in determining the success or failure of a polymer flooding process. The results of this study have shown that, if you prevented plugging at the sand surface, polymer losses in field applications plugging at the sand surface, polymer losses in field applications tended to become prohibitively difficult, specially where the formation had a high surface area per unit volume. EXPERIMENTAL PROCEDURE In this research, two basic core sizes were used. The short cores were 12 inches in length and 1.5 inches in diameter. The long cores were 5 feet in length and 1.5 inches in diameter. All of the short cores were consolidated, while long cores were not consolidated. The core porosity was determined by the bulk volume method. The absolute permeability of all cores was measured, using distilled water over equal time intervals. The fluid viscosity was measured using a modified Ostwald viscometer. All measurements were made at steady-state test conditions. In determining the loss of polymers intended for use as agents for water-flood mobility control, three parameters were evaluated. These are the polymer concentrations of the influent, the polymer concentrations of the effluent, and the loss of concentration due to adsorption on the grain surfaces. The viscosity of the solution was found to be a useful property in relating the influent and effluent polymer concentrations. Solution viscosity was, however, found to be temperature-sensitive. A constant temperature of 70F (room temperature), therefore, was maintained throughout the tests. The viscosity-concentration relationship for the synthetic polyacrylamide tested is shown in Figure 1. Two different types of sands were used to construct the long cores. p. 509
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Abstract A successful surfactant (microemulsion) flood pilot test in a watered-out portion of the Weiler pilot test in a watered-out portion of the Weiler sand, Loudon Field, Illinois (USA) was completed in October, 1981. The microemulsion system tested was designed to be effective in the presence of high-salinity formation water containing 104,000 ppm (mg/l) total dissolved solids (TDS) without use of a preflush. The test was conducted in a single, 0.68-acre preflush. The test was conducted in a single, 0.68-acre (2752 m2) 5-spot operated in a manner that approximated a confined pattern. The test was highly successful, recovering 60% of the oil remaining after waterflood. Cores from a post-flood well drilled within the pattern have confirmed the low final oil saturations and low surfactant retention achieved in the flood. Although oil recovery was excellent, loss of nobility control in the polyner drive bank and premature breakthrough of lower-salinity drive water premature breakthrough of lower-salinity drive water were observed part-way through the test. Laboratory and field studies conducted since flood termination have confirmed that loss was caused by bacterial degradation of the xanthan biopolymer used. Several biocides were tested in the laboratory and in a field injection experiment to determine their effectiveness against the bacteria contaminating the pilot. Formaldehyde was shown to kill bacteria within the formation, have negligible adsorption on reservoir rock, and permit propagation of undegraded polyner. Based on these test results, formaldehyde should protect xanthan biopolymer from bacterial degradation in future microemulsion floods at Loudon. Introduction Exxon is conducting a field pilot program to evaluate the potential of a microemulsion flooding process which can be used in high-salinity reservoirs process which can be used in high-salinity reservoirs without a brine preflush. Since the bulk of tertiary target oil amenable to surfactant flooding exists in reservoirs having brine salinities greater than 30,000 ppm (ng/l) TDS (defined here as "high salinity"), considerable incentive exists to develop such a process. Use of a preflush has certain disadvantages: flood life is extended, which increases operating costs; the preflush nay not contact all reservoir rock later contacted by lower-mobility micellar/polyner fluids, thereby reducing process performance; and large volumes of low-salinity water performance; and large volumes of low-salinity water nay not always be available for use in a preflush process. process. The pilot test was conducted in the Loudon Field, Fayette county, Illinois (USA). The reservoirs in this field are Mississippian Chester sandstones ranging in depth from 1400 to 1600 ft (427 to 488 n) subsurface. As shown in Table 1, the formation water contains about 104,000 ppm (ng/l) TDS including over 4000 ppm of divalent ions. Reservoir temperature is 78 deg. F (25.6 deg. C), oil viscosity is 5 cp (5 mPa s), and formation porosity averages about 19%. The Loudon reservoirs are in an advanced stage of depletion after 13 years of primary production and 31 years of water-flooding. It is estimated that at the economic limit of waterflooding slightly more than half of the OOIP will remain trapped as residual oil. Bragg et al. previously reported details of the pilot test, which was located on the Lewis Ripley pilot test, which was located on the Lewis Ripley lease in the Loudon Field (see Fig. 1). The test was conducted in a single, normal 5-spot pattern of 0.68 acres (2752 n2) operated in a manner to approximate a confined 5-spot. Fig. 2 shows the pilot well pattern at the reservoir sand depth of 1550 ft (472.4 n). In addition to the four injectors and central producer, the pattern contained five fiberglass-cased logging observation wells to allow use of induction and carbon/oxygen logs to monitor changes in oil saturation during the flood. The test was conducted in a small pattern to permit completing a field evaluation within a two-year permit completing a field evaluation within a two-year period and rapidly integrating results into an ongoing period and rapidly integrating results into an ongoing research program. P. 537
- North America > United States > Illinois > Fayette County (0.24)
- Europe > United Kingdom > North Sea > Central North Sea (0.24)
- North America > United States > Illinois > Hamilton County (0.24)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Introduction In the past few years, the use of gelled acid has become well known, and the benefits of its use in oil and gas well stimulation have been discussed. Also, results obtained from the use of gelled acid treatments have supported their application. Polymer systems are often used as viscosity-building agents Polymer systems are often used as viscosity-building agents for well stimulation fluids and other acidizing operations. These polymer systems must be functional under the desired acidizing polymer systems must be functional under the desired acidizing conditions. Three systems published as useful in acidizing are a liquid gelling agent; xanthan polymer and a metal cross linked polymer system. These systems impart viscosity effectively in acidic polymer system. These systems impart viscosity effectively in acidic fluids only below 200F. In the patent literature, various systems are discussed which possess utility for gelling acids. Examples of some polymer possess utility for gelling acids. Examples of some polymer systems included are acrylamide and acrylamide copolymers cross linked with various aldehydes, ethylene oxide-propylene oxide block co-polymers used at high concentrations, branched or emulsion polymers of diallyldimethyl amine, cellulose derivatives cross-linked with chromium salts, and branched polymers prepared by reacting ethylene oxide with acrylamidomethylpropane sulfonic acid (AMPS). In the above cited examples, none include rheology data above 200F, and thus their use cannot be supported above this temperature. Also, in many of the above systems, the gelling polymers' lack of chemical stability to hot, strong acid prevents polymers' lack of chemical stability to hot, strong acid prevents their being useful at elevated temperatures. The requirements for a high temperature (above 200F) acid gelling polymer include (1) chemical stability, (2) high intrinsic viscosity at application temperatures, (3) compatibility with all other materials involved in the treatment, and (4) be in a physically useful form for field mixing. A systematic evaluation physically useful form for field mixing. A systematic evaluation of the hydrolytic stability of various types of polymers was made and rheology data were obtained for various types of polymers to evaluate their temperature thinning properties (but not chemical degradation). The ability of several systems to produce viscosity (as a function of molecular weight), was studied produce viscosity (as a function of molecular weight), was studied and finally, a polymer gelling agent was selected which is useful for acidizing operations up to 400F. Available Polymers The general types of water soluble polymers which are potentially useful in well treatments and are commercially potentially useful in well treatments and are commercially available have been discussed by several recent authors. These may be grouped into two general categories: polysaccharide biopolymers and synthetic polymers prepared from olefinic monomers. In the first class, xanthan polymer has been shown to have the best acid stability with guar gum and cellulose derivatives having no applicability in hot, strong acid. The general structure of the synthetic polymers available is shown in Figure 1 along with a listing of some currently available polymer derivatives from this structure. Abbreviations for these polymers are also given in this figure. A second group of synthetic polymers not based on a vinyl backbone is composed of condensation products of ethylene oxide (PEO) or propylene oxide (PPO). These materials have no inherent acid hydrolytic instability and can be stabilized in non-acid systems with antioxidants. Polymer Hydrolytic Stability Polymer Hydrolytic Stability To select a potentially useful acid thickening agent to be used in all strengths of acid at temperatures in excess of 200F, the acid stability of various types of polymer structures was studied. At this point no consideration was given to the polymer's ability to produce viscosity or other properties, but rather what chemical structures currently available in polymers could survive contact with hot, strong acid without appreciable degradation of the polymer. p. 491
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Well Completion > Acidizing (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Abstract The Marmul heavy-oil field is located in South Oman in the province of Dhofar. The main sandstone reservoir consists of glacial deposits of Permo-Carboniferous age and contains about 2.5 billion Permo-Carboniferous age and contains about 2.5 billion barrels STOIIP of 21 degrees API crude. The field is in the stage of primary development with a current production of 45000 BPD. production of 45000 BPD. Oil production by depletion is expected to be low, while a water drive will be adversely affected by the high oil viscosity and high permeability. Thus the Marmul field offers ample scope for EOR techniques, for which two methods have been selected, viz. steam injection and polymer injection. In view of the long lead times involved early testing of these techniques is planned. This paper deals with the design of the relevant polymer flood and pilot tests. A suitable mobility polymer flood and pilot tests. A suitable mobility ratio is determined from calculated drive efficiencies and related polymer requirements', allowing for polymer retention and for viscosity grading of the polymer flood. In the selection of a candidate polymer, attention is paid to viscosifying power, retention characteristics, plugging tendency, shear stability, and last but not least maximum operational flexibility in the field. As for the latter, a liquid polymer seems preferable to a powder polymer. Results of laboratory experiments indicate that polyacrylamide emulsion polymers provide attractive polyacrylamide emulsion polymers provide attractive properties for application in Marmul. Retention in the properties for application in Marmul. Retention in the highly permeable sands is low and so is the plugging tendency. However, viscoelastic effects cause very high pressure gradients at high flow rates, which may adversely affect polymer injectivity. This can be resolved by subjecting the solution to controlled shear treatment prior to injection. Numerical simulations predict that the oil recovery is substantially enhanced by polymer injection. To have a qualitative indication of the sweep efficiency improvement in the first (inverted five-spot) pilot test, it is proposed to have the polymer drive preceded by injection of a limited polymer drive preceded by injection of a limited volume of water. The reversal in oil cut should then provide an indication of the better sweep. provide an indication of the better sweep Introduction The Marmul field, discovered in 1956 by Cities Service P.C., is located in South Oman (Fig. 1). In 1969 Petroleum Development Oman (PDO) acquired the concession and started appraisal drilling. Since 1978 the field has been developed full-scale and the first crude was produced in October 1980. The field contains a STOIIP of more than 400 million m3 of heavy crude oil, divided between three clastic units: Upper Haushi (Permo-Carboniferous) - 'stacked'reservoirs of fluvial origin, present only on the flanks of the structure, and not yet appraised indetail. Lower Haushi (Permo-Carboniferous) - complex and laterally variable glacial deposits which containmost of the STOIIP, with oil viscosities ranging from 50 to 120 mPa.s. Haima (Cambro-Ordovician) - fluvial sands generally of poor reservoir quality. A high proportion of the primary production to date has been obtained from Lower Haushi reservoirs, which also are the present target for enhanced recovery projects. projects. Production forecast studies indicate that the primary production of the viscous crude will be rather primary production of the viscous crude will be rather limited, the more so since no bottom-water drive is indicated as yet. There is evidence suggesting influx of edge water. The low recovery can be increased by pressure maintenance, but because of the unfavourable pressure maintenance, but because of the unfavourable mobility ratio the injection of water will result in early water breakthrough and long tail production at high water-cuts. For economic analysis an average recovery factor for waterflood is estimated at 20% of STOIIP. Thus the Marmul field provides ample scope for enhanced oil recovery methods which can improve the sweep efficiency by reducing the water/oil mobility ratio. Both polymer and steam drives are considered highly promising in this respect. P. 513
- Asia > Middle East > Oman > Dhofar Governorate (1.00)
- Asia > Middle East > Oman > Al Wusta Governorate > Haima (0.25)
- Phanerozoic > Paleozoic > Permian > Cisuralian > Asselian > Lower Asselian (0.84)
- Phanerozoic > Paleozoic > Carboniferous > Pennsylvanian > Upper Pennsylvanian > Gzhelian (0.84)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (1.00)
- Geology > Petroleum Play Type > Unconventional Play (1.00)
- Geology > Sedimentary Geology > Depositional Environment > Continental Environment > Glacial Environment (0.95)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.34)
- Asia > Middle East > Oman > Dhofar Governorate > South Oman Salt Basin > Marmul Field > Al-Qalata Formation (0.99)
- Asia > Middle East > Oman > Central Oman > South Oman Salt Basin > Nahr Umr Formation (0.99)
- Asia > Middle East > Oman > Central Oman > South Oman Salt Basin > Gharif Formation (0.98)
- Asia > Middle East > Oman > Central Oman > South Oman Salt Basin > Al Khlata Formation (0.98)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Conformance improvement (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Abstract A gravity-stable miscible CO2-solvent flood is underway in the Bay St. Elaine Field, South Louisiana. A 33% pore volume CO2-solvent slug was injected into a dipping water drive reservoir and is being pushed downdip by the injection of nitrogen gas. The CO2-solvent selected for this tertiary flood was tailored by the addition of methane and n-butane to the carbon dioxide. This CO2-solvent provides the density difference required to complete a gravity stable flood within the desired time period and also satisfies the minimum miscibility pressure requirenents at reservoir conditions. The paper presents laboratory experimental work performed and process design work required to performed and process design work required to undertake this type of enhanced recovery project The results obtained from slim tube tests to determine the CO2-solvent composition are presented as well as results of 12-foot sand pack displacement tests to evaluate the recovery efficiency of the selected CO2-solvent. Procedures used to determine the mixing zone lengths needed for CO2-solvent slug design are discussed along with the method of calculating critical velocity. Pressure pulse tests conducted to improve reservoir definition within the project area are reviewed. In situ residual oil saturations for the unconsolidated sand determined from pressure cores, log-inject-log water flood tests, single well partitioning tracer tests, and open hole well logs are presented. Field injection and current production data are also analyzed. The methods presented are being used to design CO2-solvent floods for reservoirs previously thought to be unsuited for conventional miscible CO2 flooding. The procedures and concepts discussed can be applied to flood design for numerous secondary and tertiary miscible CO2 projects. Introduction In order to maximize the ultimate oil recovery from the oil reservoirs of the Middle East, enhanced oil recovery (EOR) processes should be applied as soon as possible. These EOR processes could be implemented early in secondary recovery operations or, if need be, during tertiary operations. Various EOR methods could have potential application to the types of reservoirs found in the Middle East. Miscible flooding techniques look particularly attractive due to the relatively high reservoir pressures and intermediate oil gravities present in many Middle East oil reservoirs. As long as large amounts of hydrocarbon gas are available, various hydrocarbon miscible flooding methods could be implemented. However, as the market demand for excess hydrocarbon gas increases, the attractiveness of such processes will diminish. This situation has already occurred in the United States. As a result, considerable interest is now being shown in miscible carbon dioxide flooding. Texaco is currently testing several types of carbon dioxide (CO2) processes in their domestic reservoirs. As a result of laboratory studies and field tests, it has been possible to extend the range of reservoir conditions under which miscible conditions can be achieved. Texaco believes that miscible CO2 flooding is a viable process for those areas of the Middle East where adequate CO2 supplies exist or can be developed. Of course, application of such a process would have to be made on the merits of each process would have to be made on the merits of each individual reservoir. It is with a view toward future potential miscible CO2 flooding applications in the Middle East that this paper reviewing the design of the Bay St. Elaine CO2-solvent flood and evaluating the field results obtained to date is presented. PROJECT LOCATION AND DESCRIPTION PROJECT LOCATION AND DESCRIPTIONA gravity-stable miscible CO2 process can be established in a dipping reservoir by the updip injection of a properly designed miscible CO2-solvent. Gravitational forces will act to stabilize the advancing front because of the favorable density difference between the injected CO2-solvent and the more dense displaced reservoir oil and water. P. 537
- North America > United States > Louisiana (1.00)
- North America > United States > Texas > Dimmit County (0.61)
- North America > United States > Gulf of Mexico > Central GOM (0.61)
- Research Report (0.46)
- Overview (0.34)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Texas > Maverick Basin > Elaine Field > Anacacho Formation (0.99)
- North America > United States > Gulf of Mexico > Central GOM > East Gulf Coast Tertiary Basin > Eugene Island > Block 193 > Bay St. Elaine Field (0.99)