Miscible Displacement Of Oil Research Articles

Reservoir Simulations of Hydrogen Generation from Natural Gas with CO2 EOR: A Case Study

This paper addresses the problem of hydrogen generation from hydrocarbon gases using Steam Methane Reforming (SMR) with byproduct CO2 injected into and stored in a partially depleted oil reservoir. It focuses on the reservoir aspects of the problem using numerical simulation of the processes. To this aim, a numerical model of a real oil reservoir was constructed and calibrated based on its 30-year production history. An algorithm was developed to quantify the CO2 amount from the SMR process as well as from the produced fluids, and optionally, from external sources. Multiple simulation forecasts were performed for oil and gas production from the reservoir, hydrogen generation, and concomitant injection of the byproduct CO2 back to the same reservoir. EOR from miscible oil displacement was found to occur in the reservoir. Various scenarios of the forecasts confirmed the effectiveness of the adopted strategy for the same source of hydrocarbons and CO2 sink. Detailed simulation results are discussed, and both the advantages and drawbacks of the proposed approach for blue hydrogen generation are concluded. In particular, the question of reservoir fluid balance was emphasized, and its consequences were presented. The presented technology, using CO2 from hydrogen production and other sources to increase oil production, also has a significant impact on the protection of the natural environment via the elimination of CO2 emission to the atmosphere with concomitant production of H2.

Numerical modeling of viscous fingering during miscible displacement of oil by a paraffinic solvent in the presence of asphaltene precipitation and deposition

We study the mixing dynamics of a paraffinic solvent with oil in the context of miscible displacement in porous media for enhanced oil recovery. Typically, injected solvents are less viscous compared to the resident oil, leading to the rise of interfacial instabilities known as viscous fingering. This, in turn, accelerates precipitation of initially dissolved asphaltene particles in the oil. The formed precipitates are carried with the flow and may deposit in the porous media, altering porosity and permeability fields. Although asphaltene precipitation and deposition are inevitable in most of the solvent-based recovery techniques, they have been neglected in the previous works of miscible displacement due to their added complexity. In this work, we present a rigorous formulation of the physics of the problem and conduct high-resolution nonlinear numerical simulations to investigate the effects of asphaltene precipitation and deposition and the resulting formation damage. For this purpose, the related governing equations are derived based on the velocity-vorticity formulation, and a high-order hybrid scheme is applied to solve them. This type of handling enables us to simulate viscous fingering at large viscosity ratios and Peclet numbers, beyond what has been previously reported in the literature. Furthermore, experimental measurements are conducted for viscosity and asphaltene content of the oil at various solvent concentrations and are used in the simulations. The results of our numerical simulations reveal that despite having a great impact on the permeability field, asphaltene precipitation and deposition do not influence the growth of viscous fingers, noticeably, which is due to the substantial viscosity ratio of the studied system. However, deposition of the formed precipitates leads to in-situ upgrading of the oil and thus enhances the quality of the produced liquid. Finally, regarding the effect of the choice of viscosity mixing rule, we compare two commonly used viscosity mixing rules in the previous works (exponential and quarter-power) and elaborate on their main differences in terms of the observed dynamics.

A critical review of dispersion in packed beds

The phenomenon of dispersion (transverse and longitudinal) in packed beds is summarized and reviewed for a great deal of information from the literature. Dispersion plays an important part, for example, in contaminant transport in ground water flows, in miscible displacement of oil and gas and in reactant and product transport in packed bed reactors. There are several variables that must be considered, in the analysis of dispersion in packed beds, like the length of the packed column, viscosity and density of the fluid, ratio of column diameter to particle diameter, ratio of column length to particle diameter, particle size distribution, particle shape, effect of fluid velocity and effect of temperature (or Schmidt number). Empirical correlations are presented for the prediction of the dispersion coefficients (D T and D L) over the entire range of practical values of Sc and Pem, and works on transverse and longitudinal dispersion of non-Newtonian fluids in packed beds are also considered.

Technical Feasibility of CO2 Flooding in Weyburn Reservoir - A Laboratory Investigation

Abstract Miscible or near-miscible flooding with CO2 or hydrocarbon gases will significantly increase, and extend the production life of, Saskatchewan light and medium oil reserves. These pools are approaching their economic limit of production under conventional technology (primary and secondary recovery methods). Responding to industry needs, a comprehensive study by Saskatchewan Research Council is assessing the suitability of the CO2 flooding process for reservoirs in southeast Saskatchewan. This paper presents the details of a laboratory study to evaluate the applicability of CO2 flooding for a southeast Saskatchewan reservoir, Weyburn. The evaluation is based on the measurement of CO2 minimum miscibility pressure for the Weyburn reservoir fluid, of PVT properties for reservoir fluid CO2 mixtures, and of oil recovery behaviour from core flood tests conducted in the near-miscible region. Laboratory studies showed that the tertiary CO2 injection at over 12 MPa into the waterflo'oded reservoir is expected to produce miscible flooding conditions. At this pressure of injection, over 60 mol % CO2 was dissolved in the reservoir fluid. This reduced the viscosity of the fluid nearly fourfold to 0.70 mPa.s and swelled the oil about 45%. Coreflood studies indicated that the microscopic displacement efficiency of the process increased with injection pressure in the near-miscible region. It is believed that the geology of the Weybum reservoir will prove advantageous for near-miscible operation. However, this aspect needs to be further investigated. Introduction Most of Saskatchewan's light and medium oil (LMO) reservoirs have reached their economic limit of production under conventional technology. Primary and secondary methods together recover about 21% of the initial oil-in-place (IOlP). Although the remaining light and medium oil-in-place in Saskatchewan is 1,373 million cubic metres(1) the remaining reserves producible under primary and secondary recovery are only 59 million cubic metres. This latter number would rise by 20 million cubic metres if medium oil in southwest Saskatchewan, not considered here, were included(1). The development of tertiary recovery techniques is, therefore, essential to increase the production life of these reservoirs and to maintain current production. Application of the miscible or near miscible oil displacement process using CO2, hydrocarbon or other gases as injection fluids is expected to increase the LMO reserves threefold and extend the production life of these pools by two decades(2). Miscible (or near-miscible) flooding with carbon dioxide or hydrocarbon solvents is considered to be one of the most effective enhanced oil recovery (EOR) processes applicable to LMO reservoirs. A comparison of effectiveness of CO2 and hydrocarbon gases as miscible solvents has been discussed(3). CO2 floods minimize gravity segregation compared with the hydrocarbon solvents. In addition, CO2 generally costs less than hydrocarbon miscible solvents in the United States(3). There is a limited supply of CO2 in Saskatchewan and Alberta for EOR purposes. However, CO2 can be imported from the U.S. to be implemented in miscible displacement projects in Canada. Current industry interest in CO2 miscible flooding is high, as evidenced by the growing level of activity in field testing(4) and increasing production from this method worldwide.

Laboratory Experiments and Reservoir Simulation Studies in Support of CO2 Injection Project in Mattoon Field, Illinois, USA

Abstract This paper describes the results of rock and fluid property measurements and of the reservoir simulations associated with the demonstration of CO2-assisted oil recovery in the Cypress Sandstone reservoirs at Mattoon Field, Illinois. This work provided technical support for the field project. Results from core flood tests indicate that oil recovery from immiscible displacement of reservoir crude oil with carbon dioxide will increase with displacement pressure. Miscible displacement of oil with CO2 from the Cypress Sandstone reservoirs at Mattoon field is not possible. As shown by the slim-tube experiments, the minimum miscibility pressure (MMP) of Mattoon oil is close to the formation parting pressure of the Cypress Sandstone at Mattoon field. Nevertheless, phase behaviour experiments show that dissolved CO2 significantly enhanced oil recovery through oil swelling and viscosity reduction at pressures below miscibility conditions. Numerical simulations of CO2 injection into various reservoirs within the Sandstone were performed. A straight CO2injection program and a water alternating gas (WAG) injection program were simulated and compared in both the A-sandstone of the Pinnell Unit and E-sandstone interval of the Sawyer Unit. In the Pinnell Unit, the simulated results show an inefficient displacement of reservoir oil by CO2 and that neither of the two methods will be economically feasible because of the poor interwell communication and limited areal extent of the producing interval. This result is supported by the low oil recovery from the field CO2 injectivity tests in the Pinnell Unit. On the contrary, simulated results show that a significant amount of additional oil can be produced from the Sawyer Unit. The wateralternating- gas (WAG) injection program yielded more oil than water injection alone. The simulated results also indicate strategically- placed new wells will enhance the recovery of additional oil. Introduction This work provided technical support for a CO2-assisted oil recovery demonstration project funded by a cost-shared agreement (Cooperative Agreement number DE-FC22-93BCI4955) between the United States Department of Energy and American Oil Recovery, Inc. (AOR). The Mattoon Field, which is the site of the project (Figure 1), was discovered in June 1940. Development included approximately 420 producers and 90 dry holes drilled on a 4.05 ha (10 acre) well spacing. The principal reservoirs are found in the Cypress, Rosiclare and Aux Vases Sandstones of the Mississippian System (Figure 2). Secondary recovery was initiated in 1952 utilizing Pennsylvanian brine as well as treated municipal sewage water(1). The target intervals for additional oil recovery with CO2 are the Chesterian Cypress Sandstone reservoirs in the Mattoon field. In general, Cypress Sandstone reservoirs are the most prolific in Illinois(2). Recent studies(3,4,5) show that Cypress reservoir sandstones consist of four to five stacked layers having varying reservoir quality and often separated by thin shaly sandstone or calcareous beds. Because of the variations in reservoir quality, some layers are not as efficiently swept as others during water flooding. Such layers will contain more bypassed mobile oil than others. Furthermore, Cypress Sandstone reservoirs typically have high immobile oil saturation.

A Laboratory Miscible Displacement Study For the Recovery of Saskatchewan's Crude Oil

Abstract Most of Saskatchewan's light and medium oil (LMO) reservoirs have reached their economic limits of production under waterflooding, leaving 70 to 80 per cent of the initial oil-in-place (IOIP) in the reservoirs. The miscible displacement process using carbon dioxide, hydrocarbon, and other gases as solvents appears to be one of the most promising methods for these reservoirs. A laboratory study was conducted to evaluate the applicability of various solvents for the recovery of oil from a southeast Saskatchewan reservoir. The physical, chemical, and phase behavior (PVT) properties of wellhead and reservoir fluids were determined. Slim tube displacement tests were conducted between the reconstituted Pinto reservoir fluid and three solvents: carbon dioxide, ethane, and wellhead gas from the Steelman gas plant. Tests were carried out at various pressures and the reservoir temperature of 56 °C. The minimum miscibility pressures (MMPs) determined for the above three systems demonstrated that the MMP for ethane was much lower than that for carbon dioxide, which was lower than that for Steelman gas. The MMPs for ethane and carbon dioxide were below the reservoir fracture pressure. Introduction Most of Saskatchewan's light and medium oil (LMO) reservoirs have reached their economic limit of production under current technology. Primary and secondary methods together recover about 21 % of the initial oil-in-place (IOIP). Although the remaining light and medium oil-in-place in Saskatchewan is 1135 million cubic metres(1), the remaining producible reserves under primary and secondary recovery are only 65 million cubic metres. Medium oil in southwest Saskatchewan has not been considered here, but if it is included then up to 17 million cubic metres of additional oil (through primary and secondary recovery) may be recovered(1). The development of tertiary recovery techniques, therefore, is essential to increase the production life of these reservoirs and to maintain current production. Application of the miscible oil displacement process using CO2, hydrocarbon, or other gases as injection fluids is expected to increase the LMO reserves threefold and extend the production life of these pools by two decades(2). Miscible flooding with carbon dioxide or hydrocarbon solvents is considered to be one of the most effective enhanced oil recovery (EOR) processes applicable to LMO reservoirs. Current industry interest in CO2 miscible flooding is high, as evidenced by the level of activity in field testing(3,4) and CO2 source development in the United States. CO2 has a viscosity similar to hydrocarbon miscible solvents. Both types of solvent affect the volumetric sweep out because of unfavorable viscosity ratio. However, CO2 density is similar to that of oil. Therefore, CO2 floods minimize gravity segregation compared with the hydrocarbon solvents. In addition, the supply cost of CO2 is generally more favorable than hydrocarbon miscible solvents in the United States(3). However, there is no cheap source of CO2 in Canada yet. It should be noted that, since the world oil price collapse in 1986, the number of EOR projects in the United States has decreased markedly from 512 in 1986 to 366 in 1988, whereas the number of CO2 miscible projects has increased from 38 in 1986 to 49 in 1988, a 29% rise during these two years(4).

Phase Diagrams to Optimize Surfactant Solutions for Oil and DNAPL Recovery in Aquifers

AbstractPhase diagrams can be used to optimize the composition of surfactant solutions (cosurfactant/surfactant) designed for the recovery of DNAPLs at residual saturation in aquifer formations. The study also shows that the combination of cosurfactant (alcohol) and surfactant is more effective than the use of alcohols or surfactants separately. The suggested approach is based on miscible oil displacement using surfactant solutions at high concentrations. Most of the recent projects using surfactants for aquifer cleanup use low‐concentration solutions that promote immiscible oil displacement. The goal of the present study is to demonstrate the potential of optimized surfactant solutions to restore oil and DNAPL‐contaminated sites such as the one in Ville Mercier, Quebec (site contaminated with a mixture of petroleum and chlorinated solvents). The results show that alcohol/surfactant systems can be used to solubilize chlorinated solvents (TCE, PCE) and light oils (gasoline, diesel). For the dissolution of heavy and viscous oils (motor oil, ATF, creosote, Ville Mercier oil), an organic solvent must be added to the alcohol/surfactant system.

Eagle Lake Viking Miscible Displacement Laboratory Studies

Abstract A series of displacement tests was conducted on preserved reservoir core plugs to assist in estimating waterflood and miscible flood performance potential for the Eagle Lake Viking Reservoir in Saskatchewan. The reservoir rock is a heterogeneous sandstone, comprising thin interbeds of sand and shale with the sand lenses containing widely different amounts of smectite clays. To assess miscible recovery efficiencies in this complex sand, displacement tests were conducted with first-contact miscible propane and carbon dioxide solvents. Using standard waterflood relative permeabilities and a dual permeability model, all miscible displacements were matched by simulation with a Todd-Longstaff-type miscible mixing model. Introduction The Eagle Lake Viking Reservoir is located in southwest Saskatchewan as shown in Figure 1. It is a sandstone formation of Mississippian age. Discovered in 1957, one half of this 12.7 million m3 field was put on waterflood ten years later in 1967. Unfortunately, because of its low permeability, it has been possible to only inject 0.14 pore volumes of water in the subsequent 2O-year period. As a result, in the thirty years since discovery, only 15% of original oil- in-place has been produced. The cause of poor performance appears to be due to the abundant shales and days. Thin section analyses, however, show that bands of higher permeability are also found throughout the pay zone and often exist as thin to very thin sand stringers which are relatively free of days. In 1985, operations engineers decided that the half of the field which was still under primary depletion should be placed under some form of secondary recovery. Because the waterflood had been less than satisfactory, it was decided to examine miscible flooding as a potential alternative. Hence, a core flooding study using carbon dioxide as a flooding agent was designed with the following objectives;quantify carbon dioxide oil displacement efficiency;compare carbon dioxide with waterflood oil recovery; andcompare the potentially complex carbon dioxide miscible oil displacement process with a more conventional hydrocarbon solvent process using propane. To extend the initial objectives for reservoir design purposes, a fourth objective was to:obtain waterflood and miscible displacement parameters for use in numerical simulation of field applications, Reservoir Fluid and CO2 Miscibility Pressure The live oil used in this study was obtained by recombining separator gas and liquid to a bubble point pressure of 6509 kPa at 22 °C. Fluid densities were measured as a function of pressure at the reservoir temperatures of 22 °C and were matched with the Peng-Robinson(l) equation-of-state. The reference 2 characterization procedure was used and viscosity predictions were made with the Jossi, Stiel and Thodos correlation. Table 1 illustrates the accuracy or this prediction which involved proprietary correlations for heavy end parameters. This set of density and viscosity data was used in the simulation study. The oil composition is also shown in Table 1. To determine the first-contact miscibility pressure for CO2, oil and CO2 were blended in a visual cell at 22 °C. These results and the Peng-Robinson equation-of-state matches are presented in Table 2.

Pore-level visual investigation of miscible and immiscible displacements

The mechanisms of oil recovery by gas injection, with particular interest in the generation of highly viscous oil residues and asphaltene flocculation and the resulting permeability impairment, have been studied. The flow visualisation experiments were performed in high pressure heterogeneous micromodels reproduced from real rock micrographs. The visual micromodels were also employed in series with a compatible glass bead pack. Displacement experiments simulating secondary and tertiary recovery of a North Sea crude oil at 27.5 MPa and 33°C were conducted. Methane, propane and water were injected. The displacement video observations and the measurements made are presented. The pore-level investigation of immiscible gas drive revealed the importance of wettability and capillary pressure on the spontaneous movements of the fluid interfaces. Fractions of pores occupied by oil become oil-wet. Thin films of oil on these segments keep the oil phase continuous and results in the flow and recovery of oil trapped in narrow sections of the pores, even at very low capillary numbers. Further observations on oil, gas and connate water movements are also presented. Miscible displacement of oil with propane did not induce any significant precipitation of asphaltenes in pores. However, bulk mixing of propane and oil can promote asphaltenes flocculation, pore plugging and permeability impairment. The deposited materials can be partially dissolved and removed by contacting with fresh oil.

Multiple Contact Phase Behaviour In The Displacement Of Crude Oil With Nitrogen And Enriched Nitrogen

Abstract Phase behavior tests were carried out on a Nisku crude oil (a candidate reservoir for nitrogen flooding) with nitrogen and nitrogen mixed with carbon dioxide or propane. These measurements were carried out in a batch wise multiple contact mode to simulate what occurs when gas displaces oil in a porous medium. None of the mixtures achieved miscibility with the oil in four contacts at pressures up to 35 MPa. Nitrogen and methane were exchanged between the gas and oil phases in an almost 1:1 ratio, while gas enrichment with C2–5 hydrocarbons proceeded at a much slower pace. The experimental data were matched using the Peng-Robinson equation of stale. Good agreement between experimental and calculated results was obtained in most cases. This applies to the equilibrium phase compositions, as well as to the liquid phase densities and gas/oil ratios. The largest deviations were in the amount of heavy ends found in the vapour phase. Introduction Nitrogen may be applied for enhanced oil recovery (EOR) in several modes, e.g. pressure maintenance, cycling condensate reservoirs, attic oil production, producing gas-cap gas, chase gas for hydrocarbon or carbon dioxide slugs and miscible displacement of oil. These applications were discussed by Clancy et al.(1) and reviewed in detail by Sayegh et al.(2). Recently Leonard(3) summarized EOR activity worldwide. From this article it was noted that there are seven nitrogen injection projects in the U.S.A., four of which have already showed profit, while it is too early to tell the remaining three. In addition, there are three flue gas injection projects. In Canada, two ongoing floods utilize nitrogen. The first is in a Pembina Nisku reef, wherein the injection gas consists of a mixture rich in nitrogen along with carbon dioxide and light hydrocarbons. The second is the Willisden Green flood, where nitrogen is being used as a chase gas for a hydrocarbon slug. The advantages of using nitrogen for EOR include: widespread availability from air liquefaction, non-toxicity, non-flammability and non-corrosivity. In addition, the price of nitrogen appears to be competitive with that of dry hydrocarbons, although it is difficult to give more precise estimates because of the many variables involved in costing. Wilson(4) noted that nitrogen has some disadvantages in its use for enhanced oil recovery, which include:The cost of separating nitrogen from the produced hydrocarbon gases. This is offset if the produced gases are recycled into the reservoir.Nitrogen asphyxia.If air separation units are used to produce nitrogen, then a by-product stream rich in oxygen is produced. This stream has to be well separated from any hydrocarbon streams in the vicinity. In summary, the use of nitrogen in enhanced oil recovery has many advantages that can outweigh its disadvantages. This is a new topic, and there are many gaps in the information available for its proper application. It is the purpose of this work to try and fill in some of these gaps.

Mathematical Treatment Of The Miscible Displacement Problem

Abstract Miscible displacement or solvent flooding is the basis for a wide range of enhanced oil recovery methods, both thermal and non-thermal. From a mathematical standpoint, it is a difficult problem, and an improper treatment of the miscible phenomena in the simulations of various enhanced recovery methods can produce erroneous results. The purpose of this paper is to point out the difficulties of the problem, in particular for the two-dimensional case, and then offer recommendations for the solution schemes reviewed in this work. For a two-dimensional geometry, the miscible displacement problem involves the solution of the combined convective diffusion and Darcy-continuity equations. The velocity field is implicitly dependent on the solvent concentration, while an apparent diffusion coefficient tensor includes the combined effects of molecular diffusion and directional velocity disperision. The resulting system of nonlinear equations can be solved by a number of methods, none of which are entirely satisfactory. Numerical dispersion and stability are of concern. Two distinct approaches are used to solve the two dimensional convective-diffusion equation, for the general case, viz. fluids of different viscosities and densities. The first scheme involves a discretization of the convective term that results in a numerical dispersion term, which is included in the finite difference analog to eliminate a major portion of the truncation error. The second scheme utilizes a truncation error cancellation procedure, with weighted spatial averages. A third scheme based on the operator compact implicit method is reviewed for the linear problem. Direct solution is used in all schemes considered, in comparison to ADIP proposed by the previous investigators. It is shown that the degree of convergence of the finitie differencesolution to the exact solution of the differential system is governed by the characteristic ratio of convection to diffusion rates (the Peclet number), and the time step size. The paper presents a series of computational examples, showing the importance of the problem, and gives practical guidelines concerning the solution of this important problem, which enters into many recovery simulations. Introduction The convective-diffusion transport phenomenon describes the miscible displacement of oil by a solvent. Velocity dispersion enhances the diffusion process in both longitudinal and transverse directions of the gross fluid movement. The dispersion mechanism is intrinsic of the flow field and subsequently dependent on the local velocity direction. Dispersion is modelled by Fick's law with an apparent diffusion coefficient tensor of rank two to describe the inherent directional dependence. Analytical solutions are not available for the general miscible displacement problem due to reservoir heterogeneity and the nonlinearity of the governing equations. Finite difference approximations applied to the two-dimensional problem gives the standard five-point difference formulas(ll). These formulas suffer at high Peclet numbers in their inability to track sharp concentration fronts on a coarse mesh. Upstream differences for the convective term introduce a first-order numerical dispersion error which may be several orders of magnitude larger than the physical dispersion term. Central-differences reduce the numerical dispersion at the expense of second order errors which generate nonphysical oscillations or overshoot.

A High-Pressure Dry-Gas Miscible Displacement SchemeSimulation and Economics

Summary To develop an enhanced recovery scheme for theCardium E pool, the feasibility of waterflooding andgas injection was examined. A compositional modelwas developed to account for mass transfer andchanges in composition of this undersaturated, highly volatile oil system. High-pressure dry-gasinjection was desirable to achieve a high degree ofmiscibility. Introduction The Caroline Cardium E pool, discovered in June1974, is approximately 65 km (40 miles) southwest ofRed Deer, Alta. (Fig. 1). The discovery well was theHudson's Bay Oil and Gas (HBOG) 10–16–34–06W5, which was followed by the drilling of five additionalwells in the Bearberry Cardium A pool(T34, R06W5). The existence of a 23-km (14-mile) northwestextension of this Cardium trend was proved by thedrilling of the Pacific et al. Ricinus 10–22–36–08W5 inAug. 1975 and subsequently confirmed by the Pacificet al. Ricinus 11-28-35-07W5 in Jan. 1976. The arealextension involving T36, R08; T35, R07;and part ofT36, RO7 will be referred in this study as the areaoperated by Pacific Petroleums Ltd. The oil reservoirin these wells initially was referred to as the CardiumU pool. In Aug. 1976, an application was filed with theAlberta Energy Resources Conservation Board(ERCB)** requesting a special 130-ha (320-acre)spacing unit comprising either the northern orsouthern half of the section. This request was basedmainly on the marginal economics for developingthis thin-pay, narrow-type reservoir. It was approvedby the ERCB in an order prescribing drilling spacingunits in the Caroline area that became effectiveNov. 1, 1976. On this basis, the well allowable wasapproximately 9 m3/d (58 STB/D). By Dec. 1976, a total of 13 wells had been drilled inthe Pacific-operated area. At that time, based onpressure data and reservoir fluid analysis, Pacific pressure data and reservoir fluid analysis, Pacific filed an application requesting that the RicinusCardium E pool and the Bearberry Cardium A poolbe coalesced into the Caroline Cardium E pool.The ERCB's approval to this matter was given inFeb. 1977.1 As of June 1979, a total of 34 wells hadbeen drilled in the Pacific-operated area. To develop an optimum enhanced recovery schemefor the Caroline Cardium E pool in the Pacific-operatedarea, the feasibility of a waterflooding andhigh-pressure dry-gas miscible displacement schemeshave been examined in this study. A number ofpapers have emphasized the field application of papers have emphasized the field application of high-pressure dry-gas or vaporizing gas miscibledisplacement. It has been shown that a miscibledisplacement of oil with dry gas can be accomplishedif the oil is rich enough in the intermediatecomponents (C through C). The reservoir fluid fromthe Cardium E pool, being a highly volatile oil, appears to be amenable to undergo miscibledisplacement under high-pressure dry-gas injectionand involving multiple-contact miscibility of the gaswith the reservoir oil. JPT P. 359

Effect of "Rich" Gas Composition on Multiple-Contact Miscible Displacement A Cell-to-Cell Flash Model Study

Abstract A cell-to-cell flash model was used to simulate the transition, or mixing, zone between a reservoir oil and several "rich" gases for multiple-contact miscible displacements. The transition-zone properties that control The oil recovery efficiency properties that control The oil recovery efficiency were determined and are junctions of the solvent concentration in the rich gas. Results indicate that the optimum use of solvent corresponds to a solvent concentration near the minimum enrichment level. Introduction Many papers have been published on the characteristics and applications of miscible displacement of oil with hydrocarbon fluids. The distinction is clearly made between first-contact miscible displacement, where the injected hydrocarbon fluid is miscible in all proportions with the oil, and multiple-contact miscible displacement, which occurs as a result of component transfer between hydrocarbon phases during flow in the porous media. Two general types of multiple-contact porous media. Two general types of multiple-contact miscible displacements are condensing gas or "rich" gas drive, and vaporizing or high-pressure gas drive. This paper concentrates on the rich gas drive, where the main feature is the transfer of intermediate components or solvent from the injected rich gas to the oil phase. The advantage of condensing gas drive in comparison with first-contact miscible displacement is the reduced concentration of the valuable solvent component in the injected hydrocarbon fluid. The effect of solvent concentration on the displacement process is an important factor in optimizing the use of solvent. Several studies have reported the use of compositional models to investigate the condensing gas drive process. These studies were useful in obtaining a better understanding of the component transfer between the liquid and vapor phases, and its effect on the transition zone existing between the injected hydrocarbon fluid and the reservoir oil. These studies did not define subzones within the transition zone or present methods to evaluate the properties of these subzones. A detailed numerical investigation of the effect of solvent concentration in the injected rich gas upon the behavior of the transition zone has not been reposed previously. The purpose of this work is to obtain this information, which then can be applied to the simulation of reservoir performance and the design of laboratory experiments. performance and the design of laboratory experiments. A cell-to-cell flash model described by Metcalfe et al. was used in this study. OBJECTIVES The principal objective of this study is to present a method that can be used to investigate the physical properties of the transition zone existing between properties of the transition zone existing between the rich gas and the reservoir oil in miscible displacements. Only the effect of rich gas composition on these physical properties will be demonstrated. However, the method allows investigation of the effect of other variables, such as relative-permeability characteristics, pressure, and the composition of the reservoir oil. Knowledge of the physical properties of the transition zone is considered a first step toward proper design of rich gas, multiple-contact oil proper design of rich gas, multiple-contact oil recovery methods. Additional studies are necessary for the design. Though these studies are mentioned within the paper, they are beyond the scope of this work. DESCRIPTION OF STUDY The study involved simulating the displacement of a reservoir oil with five different rich gases. The composition and properties of the fluids are given in Table 1. The reservoir temperature was 231 degrees F and the reservoir pressure was 2,250 psia for all simulations. The cell-to-cell flash model with the "phase mobility option" was used to simulate the oil recovery method. One hundred cells were used. The phase mobility option uses phase mobilities, (kr/) phase, to determine the relative volume of each phase flowing from a particular cell. SPEJ P. 310

Miscible Flood Performance of the Intisar "D" Field, Libyan Arab Republic

Introduction Pressure maintenance by both crestal-gas and bottom-water injection was Pressure maintenance by both crestal-gas and bottom-water injection was initiated early in the life of the Intisar "D" reservoir to maximize oil recovery and to conserve produced gas. As of June 1974, cumulative oil recovery amounted to 496 million bbl and no significant breakthrough of injected gas was observed. A reservoir simulator confirms uniform downward miscible displacement of oil and predicts that continued high-pressure gas injection, combined with recompletion of wells, will yield a recovery efficiency of 80 percent. Introduction This paper reviews the performance of a combination miscible gas and bottom-water displacement program begun almost coincidentally with first production from the Intisar "D" field. This project is one of the largest miscible gas displacement projects implemented in any reservoir to date, with 300 to 400 MMcf of gas being reinjected daily. Water injection operations were begun in Nov. 1968, 1 month after production started, and crestal-gas injection was initiated in Dec. 1969, when the first of three 40,000-hp gas compressors was commissioned. This early supplemental recovery effort was necessary because recovery of the highly undersaturated oil in this reservoir by primary means alone would have been low. A compositional reservoir simulator was used to match the 5 years of available performance history. This match was accomplished easily and indicates that a high-pressure, vaporizing gas-drive process, which generates miscibility through interphase mass transfer, is performing very efficiently. This is the result of effective gravity drainage in the permeable and vertically homogeneous carbonate reef and of attainment of a pressure level high enough to assure miscibility. The history match provides the basis for model prediction runs that indicate that continued injection of gas at miscible conditions will result in an ultimate oil-recovery efficiency of about 80 percent of the stock tank oil originally in place in the percent of the stock tank oil originally in place in the reservoir. This is comparable with the high recovery efficiencies being achieved in some Canadian reef reservoirs where crestal miscible gas displacements have been conducted previously. Discovery and Development The Intisar "D" field was discovered in Oct. 1967 by the fourth well drilled on Occidental of Libya's 465,000-acre Concession 103. It is located in the Libyan Arab Republic's prolific Sirte Basin, 220 miles south of Benghazi and 525 miles east-southeast of Tripoli (see fig. 1). The field discovery well, Well D1-103, penetrated Paleocene carbonate reservoir rock at a depth of 8,946 ft Paleocene carbonate reservoir rock at a depth of 8,946 ft and found the oil-water contact 888 ft lower, at 9,834 ft. Production tests of this well yielded oil rates of up to Production tests of this well yielded oil rates of up to 75,000 B/D, and its productivity index was calculated to be 423 B/D/psi. Development of the field was begun in June 1968 and completed in May 1970 with the drilling of 13 producing wells, 16 water injection wells, and seven gas injection wells (see Fig. 2). In addition, 24 shallow-water source wells also were completed. The field went on stream in Oct. 1968, when production-handling facilities were completed. Geology The reservoir is almost circular in shape, with a diameter of about 3 miles, as shown in Fig. 2. JPT P. 935

Miscibility Relationships in the Displacement of Oil By Light Hydrocarbons

Abstract A knowledge of the limits of miscibility between reservoir oil and possible injection fluids is required for selection of the optimum miscible-injection fluid. Limits of miscibility can be estimated from the results of equilibrium phase-behavior experiments. They can also be determined by means of displacement experiments conducted in a high-pressure sandpack. This paper describes the equipment and procedure which have been developed for determining miscibility conditions by stable displacement. A systematic series of displacements of a West Texas reservoir oil was carried out. The results indicate that, at constant pressure, miscibility is a function only of the pseudo critical temperature of the injection gas. This fact, together with improved experimental methods, makes the displacement technique a rapid, reliable means for determining miscibility conditions. In conjunction with the displacement experiments, phase diagrams were constructed for the oil with dry gas and propane and with dry gas and ethane. Phase behavior of the methane-ethane-propane system was determined at 110 degrees F. The experimental work demonstrates the feasibility of using ethane-rich gases to reduce cost and pressure requirements for miscible displacement. Introduction In recent years, interest in the miscible displacement of oil by light hydrocarbon mixtures has been high. Many pilot and a few field scale projects have been started. These projects have made use of various methods for achieving miscibility:the LPG-slug process,the enriched-gas-drive process andthe high-pressure gas-drive process. Some field projects have been successful; the results of others are debatable. In general, projects which have performed best have involved the injection of an appreciable fraction of a pore volume of miscible material. Economical application of miscible displacement depends strongly on the cost of the miscible-injection fluid. If an appreciable fraction of a pore volume of material is required for successful application of these methods, a precise knowledge of the minimum requirements for miscibility in terms of composition of injection fluid is essential. Therefore, reliable experimental methods for determining miscibility conditions are important, and a procedure for estimating these conditions from the composition of the reservoir fluid is highly desirable. The subject of this paper is the problem of determining conditions which result in miscible displacement of oil by light hydrocarbon mixtures. Miscibility conditions can be estimated by means of equilibrium experiments conducted in a PVT cell, or they can be determined by means of high-pressure displacement experiments. This paper describes the equipment and procedure which have been developed for the determination of miscibility by high-pressure displacement experiments. These methods have been applied to the displacement of a West Texas reservoir oil with mixtures of dry gas, ethane and propane. In conjunction with the displacement experiments, triangular phase diagrams have been constructed for mixtures of the oil with dry gas and propane and with dry gas and ethane. The effect of injection-gas composition on conditions for miscible displacement in high-pressure sandpacks and cores has been the subject of several published papers. The experimental methods used in these investigations were such that displacements were unstable, and the effects of fingering and/or gravity layover are clearly evident in the results. Miscibility conditions were probably correct in spite of the instability phenomena, but the experiments evidently were time-consuming, and limited data were reported. Systematic high-pressure flow studies which would support a correlation of miscibility conditions have not been reported; however, Wilson has proposed the use of pseudo critical temperature of the injection gas as a parameter and Benham, et al, have based a miscibility correlation on observed and calculated equilibrium data. SPEJ P. 340^

Effect of Bank Size on Oil Recovery in the High-Pressure Gas-Driven LPG-Bank Process

Abstract This paper presents an analysis of the high-pressure, gas-driven LPG-slug process, based on fluid flow tests in areal models. Two types of tests were made. One series was made in low-pressure models which permitted observation of fluid movement. Three completely miscible analog fluids were used. A second series of tests was made in high-pressure models using methane, propane and a light refined oil saturated with methane at room temperature and 1,550 psig. Under the test conditions of room temperature and a pressure level of 1,550 psig, the phase diagram for the fluids used is similar to those for many of the field systems where the process is considered for use. A method for using these laboratory data to calculate field performance of the process is outlined. As a result of this work, it is concluded that small banks of LPG (5 per cent HV or less) are not effective in increasing oil recovery in horizontal reservoirs. Instead, where small banks are used, the driving gas quickly penetrates the LPG bank because of fingering and channeling; and from this point on, the process behaves essentially as an immiscible gas-injection project. The validity of this conclusion was substantiated by:laboratory studies of the effect of rate, model size and mobility ratio on miscible displacement in areal models; andcalculation of field recovery, which compared closely with actual field recovery. Introduction Field applications and pilot tests of the gas-driven, LPG-bank, oil-recovery process are on the increase. Most of these tests are employing small banks (2 to 5 per cent hydrocarbon volume) of LPG, which is miscible with both the driving gas and the oil in place, in an effort to attain an effective yet economical miscible displacement of oil by gas. The expectation of miscible displacement with small banks is based on the concepts that:lengths of solvent-oil mixed zones, measured during miscible displacements in long slim cores, are representative of those that will occur in the field; andareal sweep efficiencies measured in electrolytic model studies are applicable to miscible displacement in reservoirs.

Miscible Slug Process

Published in Petroleum Transactions, AIME, Volume 210, 1957, pages 40–47. Abstract This paper discusses a new oil recovery process called the "miscible slug process." This process involves the injection of propane or LPG into the reservoir prior to gas injection. The operating conditions are maintained so that the slug is miscible with both the reservoir oil and the injected gas phase. Thus, a miscible phase displacement is achieved, and high recoveries are obtained from the area of the reservoir contacted. The most striking discovery of the laboratory study which included displacements from cores up to 125 ft in length was that relatively small slugs of LPQ are effective over reservoir distances in the miscible displacement of oil. This snakes possible the commercial-application of the process. The important factors controlling the size of the slug are:reservoir length,reservoir fluid composition, andreservoir pressure at the displacement front. Of lesser importance are the effects of injection rate and porous medium type. Questions which have not been completely answered deal with the effects of gravity and reservoir inhomogeneities on the process. Introduction One of the major problems facing the oil industry today is recovery of the large fraction of the discovered oil which will remain unrecovered unless some new processes are found. Water-flooding has been one successful method used to increase recovery over natural depletion. But even successful water floods may leave 25–40 per cent of the pore space filled with residual oil. Recently a process which involves the use of thermal energy has been reported which may prove useful in increasing recovery from shallow reservoirs containing highly viscous crudes. This paper deals with a new oil recovery process involving use of miscible phases to displace the oil from the reservoir. Miscible phase displacement of oil has been an intriguing idea because the elimination of capillary effects in the reservoir leads to 100 per cent recovery in the areas contacted by the miscible displacing phase. The big deterrent in the past to the practice of miscible phase displacement has been the high cost involved in using large volumes of solvent in the process. The use of high pressure gas to achieve a miscible phase displacement of reservoir oil has been reported as one economically feasible method. However, this process calls for the maintenance of pressures above 3,000 psi at the displacement front.