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Collaborating Authors
SPE/DOE Enhanced Oil Recovery Symposium
Abstract The use of hydrocarbons together with steam was investigated as a means for improving recovery and other operating parameters in the interwell vertical steam-stimulation process for recovery of bitumen from oil sands. A total of 42 experiments were conducted using a two-well, 18-inch diameter, three-dimensional elemental physical simulator operating at conditions close to those anticipated in the oil sands area of interest. The results of 20 of these experiments are presented. A range of hydrocarbons from methane through ethane, propane, butane, pentane, natural gasoline, naphtha, to synthetic GCOS crude were investigated. The results of many of these experiments are presented and a number of observations and presented and a number of observations and conclusions drawn. A proposed recovery process based on this work is presented. Introduction The Athabasca deposit of the Alberta Oil Sands is one of the major petroleum deposits of the world. Its high viscosity (5,000,000 cps at reservoir conditions) and low overburden, however, provide some unique recovery problems. While it would be desirable to use high-temperature, and hence, high-pressure steam to raise the temperature of the reservoir and hence lower the viscosity to an acceptable value, the low overburden places limits on the pressure that may be used. The overburden in the deposit ranges in depth from zero along the Athabasca river valley, to 2,000 feet in the Birch Hills area. About 10% of the deposit has an overburden less than 150 feet and is amenable to strip-mining, while the deeper parts of the deposit can be recovered by use of high-pressure steam or in situ combustion. There is, however, a large in-between zone which is too deep for surface-mining and yet is too shallow to allow the use of high pressure. The Texaco lease, with an overburden of about 300 feet, lies within this zone and the intent of the work presented here was to develop a process suitable for this and like leases. It was known from field experiments conducted by Shell Oil Company in the Muskeg River area, and by Canadian Fina Oil in the Steepbank area of the Athabasca deposit, that the results of the use of steam alone at these shallow depths had not been encouraging. It was also known that low molecular weight hydrocarbons could be used to lower the viscosity of the crude, however, it was generally believed that the use of many of these additives would result in precipitation of asphaltenes from highly asphaltic crudes such as Athabasca bitumen. This work was therefore undertaken to see if a combination of hydrocarbon additives with low-pressure steam could be used to recover bitumen from the oil sands, and what adverse effects might occur. EXPERIMENTAL EQUIPMENT The experiments were conducted in a three-dimensional elemental model referred to as the 18-inch simulator, which has been briefly described elsewhere. The term "elemental model" indicates that the experimental approach is to take an element of the formation and to conduct experiments on that element at conditions comparable to field operating conditions. This type of model is useful for screening a wide variety of recovery processes, but accurate scaling of the experimental results to predictions of field performance requires a complicated mathematical performance requires a complicated mathematical manipulation of the data. (By contrast, the results from a scaled model may be more easily transferred to field performance predictions, but the problem is to design the model in the first place.)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Facilities Design, Construction and Operation > Unconventional Production Facilities > Oil sand/shale/bitumen (1.00)
Abstract Amoco Production Company installed a contained 1.5 acre (6 070m2) tertiary pilot project in the Levelland Field, Hockley County, Texas in 1978 in order to measure oil displacement that could be obtained by the carbon dioxide miscible recovery process in a completely waterflooded portion of the process in a completely waterflooded portion of the San Andres reservoir. The pilot was located in a previously waterflooded portion of the reservoir. Sizing of the pilot was portion of the reservoir. Sizing of the pilot was based on available log and core data utilizing a channel flow reservoir simulator which was designed to simulate miscible flood behavior. Special steps were taken during the drilling of the pilot wells to insure controlled placement of the bottomhole locations. Extensive reservoir delineation testing took place prior to starting carbon dioxide injection. Significant prior to starting carbon dioxide injection. Significant information concerning carbon dioxide process feasibility is anticipated from this pilot. Steps taken to design, install, and operate the pilot are described. Introduction Amoco Production Company, as operator of the Levelland Unit, recognized in 1977 the need to expand the pilot program in the Unit to evaluate the CO2 flood process. Additional "oil in the tank" recovery type pilots, sized to give performance within about 2 years, were proposed and authorized to take advantage of possible earlier opportunities to recover additional oil from this major San Andres reservoir. One tertiary recovery pilot was already underway in the form of a contained 12-acre (48 562 m2) double-five-spot injection pattern located in the central portion of the Levelland Unit (LLU), illustrated in portion of the Levelland Unit (LLU), illustrated in Figure 1. This pilot, completed in the San Andres formation, was initiated in 1972 to test the CO2 miscible displacement process. Located in an area of the reservoir that had not been significantly affected by secondary recovery operations, this 12-acre (48 562 m2) pilot was to be waterflooded to a point at which ultimate recovery under primary and secondary operations could be accurately determined. After that, carbon dioxide injection would begin. Carbon dioxide injection was delayed however, by the excellent response to the waterflooding phase, which precluded an early determination of ultimate secondary precluded an early determination of ultimate secondary recovery. Therefore, the pilot program has been, expanded to include two smaller 1.5 acre (6 070m2) single-five-spot oil recovery pilots which would provide tertiary recovery results at an earlier date provide tertiary recovery results at an earlier date to augment the existing program. The purpose of this paper is to describe the location, sizing, and paper is to describe the location, sizing, and implementation of one of the two pilots, the pilot designated as the Levelland Unit 1.5 Acre CO2 Pilot 736, named for the pilot producing well. PILOT SITE SELECTION PILOT SITE SELECTION This pilot was located in the Levelland Unit to augment and expand the evaluation of tertiary recovery in that Unit. Since there were already ongoing EOR injection projects, an experienced operating staff was available, and the CO2 injection facility already in use could be expanded to accommodate this new pilot. The major criteria used in pilot site pilot. The major criteria used in pilot site selection was:locate in a previously water-flooded area area must have relatively uniform reservoir properties avoid areas inside the secondary gas cap avoid interference with other EOR operations. Figure 1 shows the various areas in the Levelland Unit including the Secondary Miscible Project, the 12-Acre (48 562 m2) Pilot, and the Project, the 12-Acre (48 562 m2) Pilot, and the gas cap. The 1.5 acre CO2 pilot was to be located in an area of the Levelland Unit that had been thoroughly waterflooded in order to minimize the amount of secondary oil that would be recovered. To meet this criteria, the pilot needed to be located near an injection well with a high cumulative injection. To evaluate the results of high cumulative injection in wells at various distances from the injector, two existing test wells at distances of 100 and 300 ft. from a water injection well with over one million barrels of water injection were evaluated. At a distance of 300 ft., the water-oil ratio (WOR) was 19 which was sufficiently high to preclude a waterflood phase. phase.
- North America > United States > Texas > Permian Basin > Levelland Field > Wichita-Albany Formation (0.99)
- North America > United States > Texas > Permian Basin > Levelland Field > Strawn Formation (0.99)
- North America > United States > Texas > Permian Basin > Levelland Field > Abo Formation (0.99)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Miscible methods (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Abstract Xanthan biopolymer has been shown to have effective mobility control properties in highly saline environments and to resist shear degradation. The use of this material in low permeability formations has been limited because of injectivity problems arising from the presence of cellular debris. This paper presents the laboratory evaluation and field paper presents the laboratory evaluation and field testing of an enzymatic clarification process, and subsequent polymer injection in a low permeability carbonate reservoir. The studies show that increased solution viscosity and improved filterability can be achieved by prehydrating the polymer in fresh water, that the enzyme treatment can be effectively performed under field conditions, and that the process can lead to adequate polymer injectivity in a low permeability reservoir when good water quality and effective quality control procedures are maintained. Introduction Properties of certain water soluble polymers, such as polyacrylamides and the biopolymer xanthan gum, make them candidates for use in improving mobility of drive fluids in water flood and micellar flood processes. Biopolymers have the advantageous properties of resistance to degradation by shear, properties of resistance to degradation by shear, viscosity relatively insensitive to temperature and to water salinity, and low adsorption. Along with these desirable qualities, biopolymers have a potential injectivity problem when injected into potential injectivity problem when injected into low permeability reservoirs. The injectivity impairment of a biopolymer solution results from minute aggregates of incompletely dissolved polymer," inherent bacterial cellular debris, and residual proteinaceous material arising from the fermentation process. Microscopic examination of the bacterial cells indicate their dimensions to be 0.3 to 0.5 microns in diameter by 0.7 to 2.0 microns in length. Proposed methods to remove this undesirable material have included cartridge and diatomaceous earth filtration, clay flocculation, and chemical and enzymatic clarification. A field-scale treatment for removal of particulate matter from biopolymer is presented. The pilot was conducted in the San Andres Dolomite formation of West Texas. Reservoir parameters and water composition are presented in Table 1. This paper describes laboratory development, field testing and subsequent pilot injection of an enzyme treated xanthan biopolymer into this low permeability formation. LABORATORY TESTING Laboratory testing involved investigation of various aspects of biopolymer application in the pilot project and optimization of the enzyme pilot project and optimization of the enzyme clarification process for field use. Viscous biopolymer solutions require three stages of mixing: initial wetting, dissolution, and hydration which is accomplished by the application of high shear. Accepted practice involves mixing of a 0.6 to 1.0% (by weight) concentrated polymer solution (prehydration), and subsequently diluting this solution to the desired concentration. In this sequence, all mixing is in injection water. For a saline environment, maximum viscosity for a given polymer concentration is obtained when fresh water is utilized in the prehydration step. The benefit of this precedure is seen in the data presented in Table II for a 1000 g/m3 (ppm) solution presented in Table II for a 1000 g/m3 (ppm) solution of biopolymer in a brine of 80,000 g/m (ppm) total dissolved solids. The final salinity of the solution obtained by prehydrating in fresh water is equal to the salinity of the solution hydrated in 90% brine/ 10% fresh water, but the solution prehydrated in fresh water achieved twice the viscosity of the solution prepared by the accepted method. An additional benefit of prehydration in fresh water is the more complete hydration of the polymer molecules as reflected in the more favorable filtration response presented in Figure 1. presented in Figure 1.At the time of this project, the enzyme clarification of biopolymer solutions was a recent development.
- Geology > Mineral (0.67)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Dolomite (0.54)
Abstract The major objective of Project DEEP STEAM is to develop the technology required to economically recover heavy oil from deep reservoirs. One approach to achieve this objective involves the evaluation and modification to improve the thermal efficiency of the delivery processes for surface generated steam. processes for surface generated steam. A full-scale test facility for evaluation of well completion components has been constructed. The testing of insulated injection strings and high temperature packers utilizes a seventy-foot above-ground tower capable of operation to 700 degrees F and 3000 psi steam injection pressure; most of the testing has been carried out at 640 degrees F and 2100 psi injection pressure. The tower is instrumented for pressure. The tower is instrumented for measurement of parameters required to evaluate performance of individual completion performance of individual completion components. The measured parameters are analyzed through computational programs to predict the comparative economics of the well completion in a specific recovery project. Various approaches to insulation of injection strings have been investigated. Insulation materials tested include calcium silicate, mineral wool, and multi-layered radiation barriers and insulating fibers. High temperature packers from various manufacturers have also been examined. All the commercial packers tested utilized non-elastomeric sealing materials consisting of combinations of asbestos with stainless steel and carbon fibers. The results of tests for a variety of insulation and packer combinations reveal that casing temperatures and tubing heat losses can be successfully reduced by currently available components, but that most of the systems evaluated are not likely to survive long term or repeated use in their present form. Recommendations for further development of the hardware components required for improved, thermally efficient delivery systems are presented. presented Introduction Dwindling reserves of readily obtainable crude oils in the United States are compelling increased research and development activities designed to improve the effective recovery of heavy oils which are known to exist but are considered nonrecoverable by present-day technology. Thermal techniques such as steam drive and steam cycle are proving effective in the recovery of heavy oil at shallow depths. However, these techniques, which involve injection of surface generated steam through a string (typically uninsulated) to the sand face, encounter an economic depth limit of approximately 2500 feet because of the thermal and quality losses exhibited during steam transit down the wellbore. The amount of heavy oil in reservoirs below this depth is considered to be sufficiently large to encourage extensive technology development efforts for its ultimate recovery. Project DEEP STEAM was initiated in 1978 by the Department of Energy (DOE) as a part of a comprehensive enhanced oil recovery program. This project has as its objective the development of the technology required to economically recover heavy oils (less than 18 API) from deep reservoirs (greater than 2500 feet). Principal approaches are the modification of Principal approaches are the modification of delivery processes for surface generated steam in order to improve thermal efficiency, and the development of techniques for production of steam at the sand face. The discussion in this paper will be limited to the former approach. Computational methods dealing with heat loss in steam transit to the sand face have been the object of many investigations which ave resulted in both laboratory simulation and full-scale field tests.
Abstract Steamflooding can be a technically effective recovery method for carbonate reservoirs within certain parameter ranges. The attractiveness of steamflooding parameter ranges. The attractiveness of steamflooding relates to the fact that heat conduction is a powerful mechanism for influencing the oil in the low permeability matrix in a heterogeneous formation, and the permeability matrix in a heterogeneous formation, and the characteristically thick pay sections often associated with carbonate reservoirs result in relatively low heat losses to the confining strata. A numerical simulation model was used to study the effects of varying certain reservoir parameters (thickness, porosity, oil saturation, horizontal permeability, horizontal-to-vertical permeability permeability, horizontal-to-vertical permeability ratio, well spacing and stratification) on performance parameters (steam-oil ratio, oil recovery and project parameters (steam-oil ratio, oil recovery and project life). Steam-oil ratios less than 5-1/2 and recoveries greater than 80% in the heated zones were predicted for certain ranges of these parameters that are realistic for some carbonate formations. Two methods of heat scavenging were investigated using numerical simulation and physical models. The more promising method was simply drawing down the reservoir pressure by continued production after stopping steam injection, thereby generating steam by water flashing in the heated zone. This reduced steam-oil ratio by about 1-112 units in our test case, relative to continued steam injection, with only slightly reduced recovery and slightly increased project life. project life Introduction Carbonate reservoirs are generally much more heterogeneous in porosity and permeability than sandstone reservoirs because of the more complex depositional environment and the greater susceptibility of carbonates to diagenetic changes. Carbonate reservoir minerals (calcite, dolomite, gypsum, anhydrite) are in many ways more reactive than sandstone minerals (quartz feldspar, clays), and the formation water is usually more saline and has a higher divalent ion content. Average carbonate reservoir porosity and permeability are usually lower than those of typical sandstone reservoirs. Discussions of oil recovery process applicability in carbonates have been given by McCaffery et al and Ehrlich. These point out the need to consider effects of the properties outlined above as well as the usual screening criteria in selecting or designing a process. A process for carbonates must be technically suitable for low porosity, low permeability reservoirs, it must be able to tolerate the high salinity formation water and reactive rock matrix, and it needs to have an intrinsic mechanism allowing much of the reservoir volume to be affected despite gross heterogeneities. This has been recognized by industry in the sense that processes that have received the most attention for carbonate reservoir application — CO2 and hydrocarbon miscible displacement and, to a somewhat lesser extent, polymer flooding — satisfy these requirements. Miscible fluids have low viscosities, are chemically inert, and can smooth the effects of heterogeneities in that diffusion and dispersion perpendicular to the direction of flow will cause oil in lower permeability streaks to be affected. Polymer solutions can tolerate high salinity, high divalent ion formation water to a certain extent and will act to smooth heterogeneities via selective permeability reduction in high permeability zones. In this paper, we will discuss the applicability of steamflooding to carbonate reservoirs. The effectiveness of heat conduction as a heterogeneity smoothing mechanism (analogous to the effect of diffusion and dispersion in miscible processes) will be examined and the effects of a number of reservoir and operating parameters on steamflood performance will be parameters on steamflood performance will be investigated. QUESTIONS CONCERNING CARBONATE RESERVOIR STEAMFLOOD PERFORMANCE The mechanisms by which steam achieves a high displacement efficiency are well known and require little elaboration. P. 95
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Mineral (1.00)
Abstract Generating steam with an oilfield water containing a high concentration of total dissolved solids (TDS) was tested in the North Midway Field, Kern County, California. Conventional zeolite and weak acid cation exchange softeners were used for feedwater treatment, and steam was generated in a small scale oilfield boiler. Feedwaters with TDS concentrations up to 22,500 parts per million were successfully softened to "zero" parts per million were successfully softened to "zero" hardness levels and converted to 70% quality steam at 2300 psig. Results show that it is not necessary to have relatively fresh water for use in conventional oilfield steam generators. Furthermore, water treatment costs are economic. Introduction Steam is produced in most oilfield generators by force circulating the feedwater through a system of watertubes heated by hot flue gases and radiant heat emissions. Depending on operating parameters, this usually results in a mixture of 70% steam and 30% hot water (by weight) at the generator outlet and discharges directly into an injection well. There is no mechanical separation of the steam and hot water mixture nor is the remaining hot water recirculated through the heater tube to be eventually converted to steam. Because "wet" steam is produced, the water quality requirements are much less stringent than for a conventional boiler. Highly soluble sodium salts constitute most of the dissolved matter found in high TDS waters produced in western Kern County. They are tolerable produced in western Kern County. They are tolerable as feedwater constituents and can be concentrated in the hot water portion during steam generation. The solubility of these salts is quite high and increases with temperature as shown in Table 1. They should not cause serious scaling or corrosion as long as free oxygen and hardness are not present. Treating for free oxygen is relatively straight forward and will not be discussed. However, hardness removal by conventional cation exchange softening is adversely affected by high concentrations of sodium salts in the feedwater. Unpublished laboratory results indicate hardness leakage from a softener begins at TDS levels above 5,000 parts per million (ppm). At approximately 20,000 ppm, no hardness removal occurs with conventional softening. Any detectable hardness is undesirable in boiler feedwaters. This is primarily why high TDS waters have not been used in oilfield steam generators and relatively fresh waters are used. Laboratory experiments run prior to the subject field test indicated that high TDS oilfield brines can be softened to "zero" hardness levels by using weak acid softening resins. The waters tested were similar to those produced in most California heavy oil fields. Beginning in January 1978, a test was initiated to observe weak acid resin performance in the field and establish any adverse effects in a steam generator supplied with a softened high TDS feedwater. The test site was located in the North Midway Field, California (Figure 1). Feedwaters containing TDS concentrations ranging from 7,000 to 22,500 ppm and steam pressures from 500 to 2,300 psig (3,447 to 19,958 KPa) were utilized. Some of the data generated during the field test are presented in this paper. The procedures used to soften the high TDS steam generator feedwater are provided including the results of softener and steam generator performance tests. Analysis of the steam generator heater coils, verifying that scale deposition and corrosion had not occurred, are discussed. Estimated water treatment chemical costs showing the use of a high TDS feedwater to be economically viable are also presented. SOFTENING CONSIDERATIONS Since adequate water softening is an important consideration in using high TDS steam generator feedwaters, let us briefly discuss the principles involved.
- Geology > Geological Subdiscipline (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.53)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Treatment (0.68)
- North America > United States > California > San Joaquin Basin > Yowlumne Field (0.99)
- North America > United States > California > San Joaquin Basin > North Midway Field (0.99)
- Oceania > Papua New Guinea > Eastern Highlands > Petroleum Retention License 15 > Petroleum Retention License 15 (PRL 15) > Elk and Antelope Fields > Puri Formation (0.98)
- (3 more...)
Abstract Nitrogen can be produced from air separation plants at considerably less cost than the value of plants at considerably less cost than the value of an equal volume of natural gas. For this reason, nitrogen has been considered for pressure maintenance operations in gas condensate and oil reservoirs. However, the possibility that significant changes in phase equilibria and physical properties could occur in the reservoir fluid has hindered its acceptance as an injection gas. Experimental laboratory tests were conducted in which gas condensate and black oil reservoir fluids were contacted by nitrogen at reservoir conditions. The results showed that the dew point pressures of gas condensates would significantly increase and retrograde liquid could condense where the nitrogen mixes with the reservoir gas. Additional contact by nitrogen revaporized a significant amount of the condensed retrograde liquid. The results also showed that the oil formation volume factor and solution gas-oil ratio decreased, and the oil density and viscosity increased when a black-type oil was contacted by nitrogen. The experimental tests were simulated using a modified Redlich-Kwong equation of state. The results showed that this equation of state can be tuned to reliably predict the effects of nitrogen on phase equilibria and physical properties of reservoir fluids. This equation of state could subsequently be used in compositional reservoir simulators to predict overall effects of nitrogen injection on reservoir performance. Introduction Pressure maintenance is generally required for gas condensate reservoirs to prevent (or minimize) retrograde liquid loss. Pressure maintenance is also needed for volatile oil and many black oil reservoirs to improve recovery. Historically, pressure maintenance projects have utilized many different types of gas for injection. High pressure cycling projects for gas condensate reservoirs have projects for gas condensate reservoirs have generally used dry gas (lean process plant residue gas after recovery of gasoline type components), and even flue gas (88 % nitrogen) for injection. However, the current value of hydrocarbon gas essentially prohibits its use for pressure maintenance. Nitrogen can now be produced from air separation plants at considerably less cost than the value plants at considerably less cost than the value of an equal volume of natural gas. For this reason, nitrogen has been considered for pressure maintenance operations in gas condensate and oil reservoirs. General phase behavior characteristics and physical properties of reservoir fluids have been physical properties of reservoir fluids have been known for many years. Nitrogen is a component commonly found in most reservoir fluids, and methods have been presented for determining gas compressibility factors of gases containing nonhydro-carbons. However, the possibility that significant changes in phase equilibria and physical properties could occur in reservoir fluids upon properties could occur in reservoir fluids upon injection of nitrogen, has hindered its acceptance and use as an injection gas. The purpose of this study was to conduct experimental laboratory tests with several different reservoir fluids to determine the effects of contact by varying amounts of nitrogen. It was also desired to determine if an equation of state could be used to reliably predict these effects. This paper presents the results of these experimental tests. The effects of nitrogen on the phase equilibria (dew point pressure, retrograde liquid phase equilibria (dew point pressure, retrograde liquid condensation, and revaporization of liquid) of three gas condensate reservoir fluids are shown. The changes in oil formation volume factor, solution gas-oil ratio, oil viscosity, oil density, and solution gas gravity of an oil which was contacted by nitrogen are also shown. The effects of nitrogen calculated with a modified Redlich-Kwong equation of state are also compared with the experimental data.
- North America > United States > Wyoming (0.28)
- North America > United States > Texas (0.28)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Gas-condensate reservoirs (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Fluid modeling, equations of state (1.00)
Abstract The changing oil/brine saturations along linear porous media during secondary and tertiary laboratory flood experiments have been measured using an electrical field detection technique. A short length of the cylindrically shaped medium is contained within the tank circuit capacitor of a very high frequency (vhf) oscillator operating above 100 MHz. The oscillator frequency is dependent upon the material's dielectric constant, which is a sensitive function of the oil/brine saturations. The oscillator and associated electronics comprise a small, self-contained unit free to slide along the core barrel. A coaxial cable connects this assembly to an external frequency counter. Frequency (saturation) measurements can thus be made at arbitrary flood times and points along the porous medium. The cylindrical symmetry of the flow cell is advantageous, since it maximizes the pressure containment capabilities of the necessarily nonmetallic core barrel materials. The design and performance characteristics of this core saturation monitor (CSM) are described, and its response related to oil saturation and brine conductivity. Examples include saturation scans of a sand pack undergoing oil saturation and water flood. The utility of the technique is demonstrated by contrasting the oil movement characteristics of three chemical floods. Introduction Multiple phase flow through porous media has traditionally presented a difficult research problem; the opaque nature of the supporting medium does not allow the flow visualization techniques that have been so successfully applied to other fields of fluid dynamics. As a result, Most laboratory studies on oil recovery settled for relatively simple measurements of the produced fluids, disregarding their internal produced fluids, disregarding their internal distribution and movement. The development of water flooding created the need for more detailed considerations and measurements, and a variety of instrumentation was developed to provide laboratory in situ saturation measurements. Currently chemical flooding is under intensive study, and its more complicated nature requires that every possible measurement on the recovery process be used. Problems concerning oil displacement mechanisms, re-entrapment processes, scaling laws, slug integrity and mobility control all can be investigated by detailed measurements of the changing oil/brine saturations. Unfortunately, most of the earlier non-invasive measurement techniques are inappropriate for chemical flooding. Laboratory water flood saturation profiles have been monitored quite successfully profiles have been monitored quite successfully using a variety of tracers, including radio-active materials, high magnetic susceptibility materials and x-ray absorbing tracers. However, the introduction of such tracers severely influences the behavior of any surfactant systems under study. A neutron diffraction technique has been used for air/kerosene two-phase flow, but the procedure cannot differentiate between water procedure cannot differentiate between water and oil. Nuclear magnetic resonance has been used to measure whole core saturations and micellar behavior. However, the procedures were developed for small plugs procedures were developed for small plugs and are not easily adapted to the measurement of saturation profiles along a porous medium. Recently, Parsons and others have used the dipolar relaxation of water at microwave frequencies to determine localized water content of thin rectangular, porous media slabs during flooding.
Abstract Matrix and pores of rock form irregular, interpenetrating, network-like structures with interrelated shapes and connectivities that are statistical variables resulting from the nature of the original sediments and the diagenetic processes they have suffered. Transport properties of either network depend on geometry, i.e. size and shape distributions; transport depends equally on the number of transport paths, or distribution of connectivity, i.e. topology. Thus different structural properties and transport processes in rock matrix and in pore space are processes in rock matrix and in pore space are interrelated. This theoretical prediction is studied by means of the Voronoi construction for subdividing space, which provides precisely defined, realistically irregular models of rock and of distributions therein of fluids, conductivity, permeability, strength, etc. Geometry and topology of the models are coded into matrices that are useful for thinking about structure and transport, and which become factors in illustrative calculations of electrical conductivity, Young's modulus, and fracture strength as functions of, for example, porosity. The results show percolation thresholds: cessation (or onset) of transport when a critical fraction of paths is randomly blocked (or created). Statistical features of structure and transport are the subject of percolation theory. The results help focus experimental studies and point to a unified picture of structure, strength, point to a unified picture of structure, strength, and transport. Introduction Reservoir rocks are porous materials that because of their origins and history are partially ordered yet irredeemably chaotic. Their profound irregularity has defied adequate analysis and hindered understanding. Obviously some statistical concepts are needed, but distribution functions of pore sizes and grain sizes have not led deep. The reason is that the geometry of pores and grains is only half the structure of a rock. The other half is the way the pores are connected together — in a word, the topology of the rock structure. The connection patterns of the pores and of the matrix, however chaotic both may be, are not independent. Does this mean that mechanical properties of the solid matrix are related to fluid distribution properties and fluid flow properties of the pore space, properties and fluid flow properties of the pore space, and vice versa? Are there scientific bases for systematically incorporating all the conveniently measurable properties of rock in a geologically sound, physically accurate description useful for engineering physically accurate description useful for engineering the improved locating and recovering of oil? A unified picture of rock structure and transport therein is indeed emerging, as we indicate here. At the center of this picture are new means for modelling the statistical geometry and statistical topology of rock, and new concepts for dealing with essential aspects of the innate irregularity. Reservoir rocks are the "packed beds" in which oil becomes entrapped as residual, and in which chemical flooding processes are operated to enhance oil recovery. In trying to understand the distribution and flow of oil and brine in reservoir rock we discovered that concepts and results of a comparatively new physical theory fit porous media beautifully: the percolation theory of transport through irregular percolation theory of transport through irregular networks and in irregular composites. Most of the mathematical development of the theory is for circumstances in which the irregularity has major elements of randomness, but the theory is not restricted to entirely random structures. We perceive that it can be amended and extended to explain and correlate most of the peculiarities of deformation, strength, and transport in rock. Many field observations and laboratory results can be explained qualitatively with percolation concepts. In its present state of development, however, percolation theory yields quantitative predictions in percolation theory yields quantitative predictions in few cases except by Monte Carlo calculations with a model of the porous medium. It is also true that even the most careful laboratory experiments are confounded by the enormous time and expense of disassembling just a small sample of rock grain-by-grain, pore-by-pore, and recording all of the relevant dimensions and connections.
- Research Report > New Finding (0.68)
- Research Report > Experimental Study (0.68)