Carbon Dioxide Displacement of a West Texas Reservoir Oil

1982 ◽  
Vol 22 (06) ◽  
pp. 805-815 ◽  
Author(s):  
William F. Yellig
Keyword(s):  
Mass Transfer ◽  
Phase Equilibria ◽  
Oil Recovery ◽  
Miscible Displacement ◽  
Pilot Test ◽  
Co2 Flooding ◽  
Process Data ◽  
Analytical Technique ◽  
West Texas ◽  
Pilot Tests

Yellig, William F., SPE, Amoco Production Co. Abstract This paper presents results of an extensive study to understand CO2 displacement of Levelland (TX) reservoir oil. The work was conducted to support Levelland CO2 pilots currently in progress. Experimental displacement tests were conducted at various pressures, core lengths, and CO2 frontal advance rates. The experimental system included a novel analytical technique to obtain effluent compositional profiles within the oil-moving zone at test conditions. The results of this study show that at pressures greater than the CO2 minimum miscibility pressure (MMP), a multicontact miscible displacement mechanism predominates. Miscibility is developed in situ by vaporization or extraction-type mass transfer. The laboratory lengths required for CO2 to develop miscibility and exhibit miscible displacement efficiency were found dependent on the phase equilibria of the CO2/Levelland oil system. Displacements requiring the greatest length to develop miscibility were at pressures where single-contact mixtures of CO2 and Levelland oil form two liquid phases. A companion paper demonstrates the use of the analytical technique developed in this study to obtain process data from a CO2 field pilot test. In addition, the mechanistic information obtained from this study is used to interpret the process data from the pilot test. The results have application to other reservoir oils whose phase equilibria with CO2 are similar to the CO2/ Levelland oil system. Introduction Miscible CO2 flooding is developing rapidly as a commercial enhanced oil-recovery process. The successful design and interpretation of CO2 pilot tests and fieldwide floods are dependent on a good knowledge of the reservoir and the CO2 displacement process. The overall CO2 displacement process is shown schematically in Fig. 1. The main focus of this study concerned the oil moving zone (OMZ) and particularly the mechanisms by which this zone formed and by which CO2 displaced Levelland oil. Levelland oil was chosen because it is typical of many west Texas reservoir oils being considered for CO2 flooding. In addition, the CO2 pilot tests currently conducted in the Levelland field provide a direct application of this research. Several authors have discussed the displacement of reservoir oil by CO2. These discussions have centered around three primary displacement mechanisms: immiscible, multicontact or developed miscible, and contact miscible. In addition, two basic types of mass transfer have been postulated as responsible for the development of miscibility in a multicontact process: transfer of hydrocarbons from the in-place oil to the displacing CO2 (i.e., vaporization or extraction) and transfer of CO2 to the in-place oil (i.e., condensation). Vaporization and extraction are the same basic mass-transfer process. Vaporization refers to mass transfer from a liquid oil phase to a CO2-rich vapor phase and extraction refers to mass transfer from a liquid oil phase to a CO2-rich liquid phase. The distinction between vaporization and extraction is somewhat arbitrary in describing the CO2 process since it reflects the types of phases present only on first contact. One purpose of this paper is to present results of a comprehensive study to determine the mechanism by which CO2 displaces Levelland oil at reservoir conditions. SPEJ P. 805^

The Effect of Phase Equilibria on the CO2 Displacement Mechanism

1979 ◽  
Vol 19 (04) ◽  
pp. 242-252 ◽  
Author(s):  
R.S. Metcalfe ◽  
Lyman Yarborough
Keyword(s):  
Carbon Dioxide ◽  
Phase Equilibria ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Miscible Displacement ◽  
Co2 Flooding ◽  
Recovery Method ◽  
Two Fluids ◽  
Reservoir Conditions

Abstract Carbon dioxide flooding under miscible conditions is being developed as a major process for enhanced oil recovery. This paper presents results of research studies to increase our understanding of the multiple-contact miscible displacement mechanism for CO2 flooding. Carbon dioxide displacements of three synthetic oils of increasing complexity (increasing number of hydrocarbon components) are described. The paper concentrates on results of laboratory flow studies, but uses results of phase-equilibria and numerical studies to support the conclusions.Results from studies with synthetic oils show that at least two multiple-contact miscible mechanisms, vaporization and condensation, can be identified and that the phase-equilibria data can be used as a basis for describing the mechanism. The phase-equilibria change with varying reservoir conditions, and the flow studies show that the miscible mechanism depends on the phase-equilibria behavior. Qualitative predictions with mathematical models support our conclusions.Phase-equilibria data with naturally occurring oils suggest the two mechanisms (vaporization and condensation) are relevant to CO2 displacements at reservoir conditions and are a basis for specifying the controlling mechanisms. Introduction Miscible-displacement processes, which rely on multiple contacts of injected gas and reservoir oil to develop an in-situ solvent, generally have been recognized by the petroleum industry as an important enhanced oil-recovery method. More recently, CO2 flooding has advanced to the position (in the U.S.) of being the most economically attractive of the multiple-contact miscibility (MCM) processes. Several projects have been or are currently being conducted either to study or use CO2 as an enhanced oil-recovery method. It has been demonstrated convincingly by Holm and others that CO2 can recover oil from laboratory systems and therefore from the swept zone of petroleum reservoirs using miscible displacement. However, several contradictions seem to exist in published results.. These authors attempt to establish the mechanism(s) through which CO2 and oil form a miscible solvent in situ. (The solvent thus produced is capable of performing as though the two fluids were miscible when performing as though the two fluids were miscible when injected.) In addition, little experimental work has been published to provide support for the mechanisms of multiple-contact miscibility, as originally discussed by Hutchinson and Braun.One can reasonably assume that the miscible CO2 process will be related directly to phase equilibria process will be related directly to phase equilibria because it involves intimate contact of gases and liquids. However, no data have been published to indicate that the mechanism for miscibility development may differ for varying phase-equilibria conditions.This paper presents the results of both flow and phase-equilibria studies performed to determine the phase-equilibria studies performed to determine the mechanism(s) of CO2 multiple-contact miscibility. These flow studies used CO2 to displace three multicomponent hydrocarbon mixtures under first-contact miscible, multiple-contact miscible, and immiscible conditions. Results are presented to support the vaporization mechanism as described by Hutchinson and Braun, and also to show that more than one mechanism is possible with CO2 displacements. The reason for the latter is found in the results of phase-equilibria studies. SPEJ P. 242

Effects of Impurities on Minimum Miscibility Pressures and Minimum Enrichment Levels for CO2 and Rich-Gas Displacements

1982 ◽  
Vol 22 (02) ◽  
pp. 219-225 ◽  
Author(s):  
R.S Metcalfe
Keyword(s):  
Oil Recovery ◽  
Control Variable ◽  
Quantitative Measure ◽  
Miscible Displacement ◽  
Co2 Flooding ◽  
Liquefied Petroleum Gas ◽  
Improved Oil Recovery ◽  
Hydrocarbon Component ◽  
Miscible Flooding ◽  
System Temperature

Abstract Multicontact miscible displacement processes are becoming increasingly popular as a means of recovering secondary and tertiary oil reserves in the U.S. and Canada. Economics of multicontact miscible flooding are governed to some extent by the availability of large sources of high purity CO2 or suitable liquefied petroleum gas (LPG) streams. This is because achievement of miscibility depends on the solvent composition as well as the system temperature and pressure. Atypical components in a CO2 or solvent stream therefore may increase the required pressure or enrichment levels for achievement of miscibility. Several papers have been published discussing the pressure (for CO2) and composition (for rich gas) levels required for miscible displacement. The potential CO2 supply could be increased if complicated cleanup procedures for injected and produced fluids were not required. For engineering studies it is important that CO2 streams containing H2S and hydrocarbons be evaluated for their miscible flooding potential. It is also important to evaluate the effects of CO2 and C5+ components in rich gas mixtures to determine whether they can be used to reduce calculated enrichment levels for solvent systems. This paper presents results of studies using mixtures of CO2, H2S, and C1, CO2-LPG, and rich gas solvents containing CO2 or C5 to displace oil miscibly in slimtube experiments. The purpose of this work is to show the effects of various components on pressure and compositions required for miscibility. As expected, the changes in CO2 miscibility pressure are direct functions of temperature. It is reported that the addition of H2S and C2+ hydrocarbons lowers the miscibility pressure for CO2, whereas the presence of C1 in a CO2 solvent increases it. More important, the results give a quantitative measure of the degree of reduction/elevation in miscibility pressure to be expected with impure CO2 streams. The paper also presents similar results from displacements with typical rich gas solvents mixed with CO2 and/or C5. It is reported that CO2 increases the minimum enrichment required, while a heavier hydrocarbon component actually can reduce anticipated enrichment levels. Introduction The use of miscible gas flooding as an improved oil recovery technique is increasing rapidly. CO2 in particular is being tested in at least 16 pilot or fieldwide floods. Multicontact miscible (CO2 and rich gas) processes are pressure and/or composition dependent - i.e., a certain pressure is required before a gas of given composition can miscibly displace a given crude oil. The pressure level required for mlticontact miscibility is therefore an important control variable. Control of this pressure can help to increase the number of economically feasible miscible projects. Of more importance, perhaps, is the ability to select a CO2 or LPG stream of less than 100% purity with the assurance that some minor concentration of H2, N2, C1, H2S, or C2 through C4 will not affect the performance adversely. Benham,1 Rutherford,2 and Jacobson,3 by monitoring recovery from slim-tube or core tests, have looked at ways in which C1, C2, C3, or C4 concentrations affect miscibility pressure. This research was important for understanding the compositional relationships between solvent and oil in the hydrocarbon multicontact miscible process. Jacobson also studied effects of H2S on displacement efficiencies of a C1 drive gas. Generally, these papers considered rather large concentrations of hydrocarbons, H2S, or CO2 in C1. The effects of N2 or C1 contaminants on the pressure required for CO2 flooding have been discussed most recently by Graue and Zana.4

Stability of CO2 Displacement of an Immiscible Heavy Oil in a Reservoir

SPE Journal ◽  
2017 ◽  
Vol 22 (02) ◽  
pp. 539-547 ◽  
Author(s):  
Truynh Quoc Tran ◽  
P.. Neogi ◽  
Baojun Bai
Keyword(s):  
Mass Transfer ◽  
Miscible Displacement ◽  
Immiscible Displacement ◽  
Heavy Oils ◽  
Co2 Flooding ◽  
Gas Oil ◽  
Oil Viscosity ◽  
Restricted Form ◽  
Heavy Crude ◽  
Carbon Dioxide Co2

Summary Miscibility is not reached in carbon dioxide (CO2) flooding for recovery of heavy oils. Thus, an important advantage of no gas/oil surface tension is lost. Nevertheless, some CO2 continues to dissolve in oil and reduces the oil viscosity, which makes the displacement easier. This is an asset that remains. However, the viscosity of heavy crude is much higher than the viscosity of CO2, causing the displacement process to be unstable and leading to fingering or channeling. We have undertaken the linear-stability analysis of the displacement process, which is that of immiscible displacement but includes mass-transfer effects. All stabilizing/destabilizing mechanisms of both immiscible displacement and miscible displacement are included. A number of stabilizing mechanisms related to mass transfer have been identified. We are able to provide a numerical evaluation of the results that show the lowering of viscosity that is considered only in miscible displacement leads to a partial stabilizing effect that overcomes a large destabilizing effect of the adverse mobility ratio. There is a restricted form of instability that would only give rise to a mushy zone at the front. The two regions are separated at a wavenumber determined numerically as 0.531 cm−1. We are also able to show that in the limit that the solubility of CO2 in oil drops to zero, the above window of instability becomes infinite.

Use of Full-Field Simulation to Design a Miscible CO2 Flood

1999 ◽  
Vol 2 (03) ◽  
pp. 230-237 ◽  
Author(s):  
F.P. Brinkman ◽  
T.V. Kane ◽  
R.R. McCullough ◽  
J.W. Miertschin
Keyword(s):  
Oil Recovery ◽  
Three Dimensional ◽  
Simulation Models ◽  
Co2 Flooding ◽  
Full Field ◽  
West Texas ◽  
Field Simulation ◽  
Field Modeling ◽  
Geologic Model ◽  
Carbonate Buildup

Summary A study using full-field reservoir modeling optimized the design of a miscible CO2 flood project for the Sharon Ridge Canyon Unit. The study began with extensive data gathering in the field and building a full-field three-dimensional geologic model. A full-field simulation model with relatively coarse gridding was subsequently built and used to history match the waterflood. This waterflood model highlighted areas in the field with current high oil saturations as priority targets for CO2 flooding and generated a forecast of reserves from continued waterflooding. Predictions for the CO2 flood used an in-house four-component simulator (stock tank oil, solution gas, water, CO2. A full-field CO2 model with more finely gridded patterns was built using oil saturations and pressures at the end of history in the waterflood model. The CO2 model identified the best patterns for CO2 flooding and was instrumental in selecting a strategy for sizing the initial flood area and in determining the size, location, and timing of future expansions of the CO2 flood. Introduction The Sharon Ridge Canyon Unit (SRCU) is located in West Texas, about 70 miles northeast of the city of Midland. The Unit covers 13,712 acres. Fig. 1 shows the Horseshoe Atoll, a trend of more than 40 oil fields covering several West Texas counties. SRCU is geologically continuous with the Diamond M Unit and the giant Kelly-Snyder Field (SACROC Unit) to the northeast. Production is from the Canyon Reef formation, a thick carbonate buildup of late Pennsylvanian Canyon and Cisco age, and occurs at an average depth of 6600 feet. There are active CO2 floods in this formation at SACROC, Reinecke, and the Salt Creek field. Sharon Ridge was discovered in 1949 and developed on 40 acre spacing by 1953 with about 340 wells. The reservoir initially contained undersaturated oil at 3135 psi. Production was by expansion drive until 1952 when pressure fell below the bubble point of 1850 psi over most of the field. In 1955, the field was unitized and a peripheral waterflood was started to stabilize reservoir pressure. The waterflood is now at a mature stage with oil recovery approaching 50% of the original oil-in-place (OOIP). There has been limited infill drilling with 22 wells drilled at 20-acre spacing. Screening studies identified SRCU as a good candidate for a miscible CO2 flood project. These studies included core flood displacements, pattern element simulation models, and detailed evaluations of similar fields with CO2 floods. Laboratory core displacements showed a remaining oil to waterflood of over 40% with subsequent injection of CO2 reducing oil saturation to less than 10%. Simulations with small element models have also shown significant incremental oil recovery from injection of CO2 at SRCU. SRCU has reservoir properties similar to SACROC which has reported significant additional oil recovery from miscible CO2 flooding (Ref. 1). The goal of full-field modeling was to design a miscible CO2 flood with maximum economic potential. Key issues for project design include the amount and location of remaining oil, reservoir sweep efficiency, flood rate, gas injection volume, strategy for handling increased produced gas, and projection of continued secondary operations. To address these issues, we built three different full-field three-dimensional (3D) models: geologic model, coarse-grid waterflood model, and fine-grid CO2 flood model. Recent advances in computer technology made this approach possible as opposed to the prior approach of running type-element models and scaling up those results to field rates. The approach of using field-scale simulation models to study optimizations for another CO2 flood in West Texas has been reported in Ref. 2. Thus, advancing technology and prior experience led us to embark on this ambitious approach to use full-field modeling to design our CO2 flood. Geologic Modeling Geology. The reservoir is a thick carbonate buildup that is predominately limestone. Fig. 2 shows the structure on the top of the reservoir. Geographic areas of the field have been named: North End, South End, and Southeast Pinnacle. The topography is extremely variable, with the hydrocarbon column averaging 115 feet and ranging to a maximum of 450 feet in the South End area of the field. A large portion of the North End has over 90 feet of gross reservoir thickness above the original oil-water contact. Table 1 is a summary of reservoir rock and fluid properties. The reservoir has been subdivided into five depositional sequences or zones, four of which are shown in Fig. 3. The lower zones (4, 5) are found over almost the entire field while upper zones (1, 2, 3) are more areally restricted. Zones are usually separated by intervals of low porosity limestone with few shales in the reservoir. Most wells drilled during initial field development did not penetrate the entire reservoir, thus limiting description of the lower zones. A more detailed discussion of the geologic setting and depositional facies is available in Ref. 3. Model Design. Building a full-field 3D geologic model of SRCU presented several unique challenges, including having modern porosity logs on only a few wells and only 90 full penetrations of the reservoir. To address this problem of limited data, an extensive data acquisition program was implemented. This program included deepening 19 wells, coring 11 wells, and obtaining 49 miles of new two-dimensional (2D) seismic lines. After gathering these data, all new and old core, well log, and seismic data were integrated to develop a sequence stratigraphic reservoir framework.

Simulation of Miscible Displacement in Full-Diameter Carbonate Cores

1982 ◽  
Vol 22 (05) ◽  
pp. 647-657 ◽  
Author(s):  
J.P. Batycky ◽  
B.B. Maini ◽  
D.B. Fisher
Keyword(s):  
Oil Recovery ◽  
Water Saturation ◽  
Accurate Determination ◽  
Miscible Displacement ◽  
Carbonate Reservoir ◽  
Core Material ◽  
Immiscible Fluid ◽  
Displacement Efficiency ◽  
Carbonate Cores ◽  
Capacitance Model

Abstract Miscible gas displacement data obtained from full-diameter carbonate reservoir cores have been fitted to a modified miscible flow dispersion-capacitance model. Starting with earlier approaches, we have synthesized an algorithm that provides rapid and accurate determination of the three parameters included in the model: the dispersion coefficient, the flowing fraction of displaceable volume, and the rate constant for mass transfer between flowing and stagnant volumes. Quality of fit is verified with a finite-difference simulation. The dependencies of the three parameters have been evaluated as functions of the displacement velocity and of the water saturation within four carbonate cores composed of various amounts of matrix, vug, and fracture porosity. Numerical simulation of a composite core made by stacking three of the individual cores has been compared with the experimental data. For comparison, an analysis of Berea sandstone gas displacement also has been provided. Although the sandstone displays a minor dependence of gas recovery on water saturation, we found that the carbonate cores are strongly affected by water content. Such behavior would not be measurable if small carbonate samples that can reflect only matrix properties were used. This study therefore represents a significant assessment of the dispersion-capacitance model for carbonate cores and its ability to reflect changes in pore interconnectivity that accompany water saturation alteration. Introduction Miscible displacement processes are used widely in various aspects of oil recovery. A solvent slug injected into a reservoir can be used to displace miscibly either oil or gas. The necessary slug size is determined by the rate at which deterioration can occur as the slug is Another commonly used miscible process involves addition of a small slug within the injected fluids or gases to determine the nature and extent of inter well communication. The quantity of tracer material used is dictated by analytical detection capabilities and by an understanding of the miscible displacement properties of the reservoir. We can develop such understanding by performing one-dimensional (1D) step-change miscible displacement experiments within the laboratory with selected reservoir core material. The effluent profiles derived from the experiments then are fitted to a suitable mathematical model to express the behavior of each rock type through the use of a relatively small number of parameters. This paper illustrates the efficient application of the three-parameter, dispersion-capacitance model. Its application previously has been limited to use with small homogeneous plugs normally composed of intergranular and intencrystalline porosity, and its suitability for use with cores displaying macroscopic heterogeneity has been questioned. Consequently, in addition to illustrating its use with a homogeneous sandstone, we fit data derived from previously reported full-diameter carbonate cores. As noted earlier, these cores were heterogeneous, and each of them displayed different dual or multiple types of porosity characteristic of vugular and fractured carbonate rocks. Dispersion-Capacitance Model The displacement efficiency of one fluid by a second immiscible fluid within a porous medium depends on the complexity of rock and fluid properties. SPEJ P. 647^

An Overview: Analysis of Heat and Mass Transfer in Fractal Media by Fractal Geometry and Technique

2010 ◽  
Author(s):  
Boming Yu
Keyword(s):  
Heat Transfer ◽  
Mass Transfer ◽  
Porous Media ◽  
Heat And Mass Transfer ◽  
Oil Recovery ◽  
Fractal Geometry ◽  
Boiling Heat Transfer ◽  
Nucleate Boiling ◽  
Fractal Media ◽  
Nucleate Boiling Heat Transfer

In the past three decades, fractal geometry and technique have received considerable attention due to its wide applications in sciences and technologies such as in physics, mathematics, geophysics, oil recovery, material science and engineering, flow and heat and mass transfer in porous media etc. The fractal geometry and technique may become particularly powerful when they are applied to deal with random and disordered media such as porous media, nanofluids, nucleate boiling heat transfer. In this paper, a summary of recent advances is presented in the areas of heat and mass transfer in fractal media by fractal geometry technique. The present overview includes a brief summary of the fractal geometry technique applied in the areas of heat and mass transfer; thermal conductivities of porous media and nanofluids; nucleate boiling heat transfer. A few comments are made with respect to the theoretical studies that should be made in the future.

The Combined Flooding of Dispersed Particle Gel and Surfactant for Conformance Control and EOR: From Experiment to Pilot Test

2021 ◽  
Author(s):  
Xia Yin ◽  
Tianyi Zhao ◽  
Jie Yi
Keyword(s):  
Oil Recovery ◽  
Formation Energy ◽  
High Salinity ◽  
Surfactant Solution ◽  
Pilot Test ◽  
Control Performance ◽  
Core Flooding ◽  
Displacement Efficiency ◽  
Conformance Control ◽  
And Performance

Abstract The water channeling and excess water production led to the decreasing formation energy in the oilfield. Therefore, the combined flooding with dispersed particle gel (DPG) and surfactant was conducted for conformance control and enhanced oil recovery in a high temperature (100-110°C) high salinity (>2.1×105mg/L) channel reservoir of block X in Tahe oilfield. This paper reports the experimental results and pilot test for the combined flooding in a well group of Block X. In the experiment part, the interfacial tension, emulsifying capacity of the surfactant and the particle size during aging of DPG were measured, then, the conformance control and enhanced oil recovery performance of the combined flooding was evaluated by core flooding experiment. In the pilot test, the geological backgrounds and developing history of the block was introduced. Then, an integrated study of EOR and conformance control performance in the block X are analyzed by real-time monitoring and performance after treatment. In addition, the well selection criteria and flooding optimization were clarified. In this combined flooding, DPG is applied as in-depth conformance control agent to increase the sweep efficiency, and surfactant solution slug following is used for improve the displacement efficiency. The long term stability of DPG for 15 days ensures the efficiency of in-depth conformance control and its size can increase from its original 0.543μm to 35.5μm after aging for 7 days in the 2.17×105mg/L reservoir water and at 110°C. In the optimization, it is found that 0.35% NAC-1+ 0.25% NAC-2 surfactant solution with interfacial tension 3.2×10-2mN/m can form a relatively stable emulsion easily with the dehydrated crude oil. In the double core flooding, the conformance control performance is confirmed by the diversion of fluid after combined flooding and EOR increases by 21.3%. After exploitation of Block X for 14 years, the fast decreasing formation energy due to lack of large bottom water and water fingering resulted in a decreasing production rate and increasing watercut. After combined flooding in Y well group with 1 injector and 3 producers, the average dynamic liquid level, daily production, and tracing agent breakthrough time increased, while the watercut and infectivity index decreased. The distribution rate of injected fluid and real-time monitoring also assured the conformance control performance. The oil production of this well group was increased by over 3000 tons. Upon this throughout study of combined flooding from experiment to case study, adjusting the heterogeneity by DPG combined with increasing displacement efficiency of surfactant enhanced the oil recovery synergistically in this high salinity high temperature reservoir. The criteria for the selection and performance of combined flooding also provides practical experiences and principles for combined flooding.

Enhanced Oil Recovery with the Ionic Liquid Trihexyl(tetradecyl)phosphonium Chloride: A Phase Equilibria Study at 75 °C

2013 ◽  
Vol 27 (10) ◽  
pp. 5806-5810 ◽  
Author(s):  
Sara Lago ◽  
María Francisco ◽  
Alberto Arce ◽  
Ana Soto
Keyword(s):  
Ionic Liquid ◽  
Phase Equilibria ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Phosphonium Chloride
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