Our Publications

Gas EOR

Title: Analysis of a Single-Well Chemical Tracer Test To Measure the Residual Oil Saturation to a Hydrocarbon Miscible Gas Flood at Prudhoe Bay

Authors: A.P. Cockin, L.T. Malcolm, BP Exploration Co.; P.L. McGuire, Arco Alaska; R.M. Giordano, Arco E&P

Technology; C.D. Sitz, Chemical Tracers

SPE Reservoir Evaluation & Engineering Volume 3, Number 6 December 2000 Pages 544-551

Copyright 2000. Society of Petroleum Engineers

In 1990, a single-well chemical tracer (SWCT) test was performed in Prudhoe Bay to measure the effective water flood and miscible gas flood residuals over a 12 ft reservoir interval. This is believed to be the first such use of this technology for a hydrocarbon miscible gas. This paper describes how the usual SWCT design was modified to accommodate the miscible gas, the results of the SWCT, which indicate significantly higher residual oil saturation for miscible gas flood than expected from core flood experiments, and the subsequent simulation of the test which has provided good agreement with the observed results. The paper shows, with compositional simulation support, that the high apparent residual oil saturation was a consequence of incomplete volumetric sweep by the miscible gas and draws on the experiences of this test to make recommendations for the design of future SWCT tests measuring residuals to gas flooding.


Title: A New Approach to Forecasting Miscible WAG Performance at the Field Scale

Authors: Giordano, R.M., ARCO Exploration and Production Technology; Redman, R.S., ARCO Alaska, Inc.; Bratvedt, F., Technical Software Consultants, AS

SPE Reservoir Evaluation & Engineering Volume 1, Number 3 June 1998 Pages 192-200

Copyright 1998. Society of Petroleum Engineers

Full-field EOR performance predictions are generally obtained from scale-up tools, since three-dimensional finite-difference simulations would be too CPU intensive. Existing scale-up techniques require the user to define pattern elements and then to derive performance curves to apply to each injector-producer pair in the elements. Accurate assignment of these elements is difficult because the actual shape and size of the swept volumes are sensitive to reservoir faulting, well rate changes, and regional flux. In reality, the actual sweep region is not an input parameter, but should be determined by the regional pressure field which changes as well rates vary and new wells are drilled. Thus, a major source of error in using existing scale-up tools is trying to define representative pattern elements. In the current paper, we describe a scale-up technique in which the user does not have to define pattern elements or injector-producer pairs. In the new technique, the pressure field is computed at each time step and then a front-tracking algorithm propagates water and miscible injectant throughout the reservoir. By using an analogy between oil mobilization and adsorption/desorption of tracers, the miscible-gas process is modeled. The parameters for the model are obtained by fine-scale, two-dimensional, compositional, finite-difference simulations in a vertical cross-section. In the new approach, the injected solvent is divided into an effective and an ineffective portion. This approach reduces a three-dimensional problem to a two-dimensional, areal one in which the declining displacement efficiency of the solvent, which is caused by vertical effects, is captured by decreasing the injected concentration of effective solvent with time. In this paper, we show how the new scale-up tool has been used to model the miscible WAG process in the Eastern Peripheral Wedge Zone of the Prudhoe Bay field. We show a comparison between field response and model predictions.


Title: An Overview of Streamline Tracer Modeling of Miscible/Immiscible WAG Injection IOR

Authors: Giordano, R.M., ARCO Exploration and Production Technology; Redman, R.S., ARCO Alaska, Inc.; Bratvedt, F., Technical Software Consultants, AS

SPE Reservoir Evaluation & Engineering Volume 1, Number 3 June 1998 Pages 192-200

Copyright 1998. Society of Petroleum Engineers

The streamline-based tracer model1 has been successfully deployed to history match and predict miscible and immiscible Water Alternating Gas (WAG) processes at the field scale. The tracer model is a simplified method for the three-phase WAG process, and is computed parallel to the traditional streamline waterflood model. This paper provides an overview to illustrate the relevant concepts and applications of the streamline-based tracer model. A Prudhoe Bay example of the vertical Miscible Injection Stimulation Technique (MIST) is presented to demonstrate and to verify the field use of the tracer model.


Title: Design, Implementation and Simulation Analysis of a Single-Well Chemical Tracer Test To Measure the Residual Oil Saturation to a Hydrocarbon Miscible Gas at Prudhoe Bay

Authors: Cockin, A.P., Malcolm, L.T., BP Exploration Co. Ltd.; McGuire, P.L., ARCO Alaska Inc.; Giordano, R.M., ARCO Exploration and Production Technology.; Sitz, C.D., Chemical Tracers, Inc.

SPE Annual Technical Conference and Exhibition, 27-30 September 1998, New Orleans, Louisiana

Copyright 1998, Society of Petroleum Engineers

In 1990 a single well chemical tracer (SWCT) test was performed in Prudhoe Bay to measure the effective water flood and miscible gas flood residuals over a 12 ft reservoir interval. This is believed to be the first such use of this technology for a hydrocarbon miscible gas. This paper describes how the usual SWCT design was modified to accommodate the miscible gas, the results of the SWCT, which for the miscible gas part were significantly higher than miscible gas coreflood residuals, and the subsequent simulation of the test which has provided good agreement with the observed results. The paper explains, with simulation support, what caused the measured residuals to be higher than expected, and draws on the experiences of this test to make recommendations for the design of future SWCT tests measuring residuals to gas flooding.


Title: The Effects of Dispersion and Phase Behavior on Unfavorable Mobility Ratio Displacements

Authors: Giordano, R.M., Salter, S.J., ARCO Oil and Gas Co.

SPE Annual Technical Conference and Exhibition, 16-19 September 1984, Houston, Texas

Copyright 1984 Society of Petroleum Engineers of AIME

A compositional simulator is used to show how dispersion and phase behavior influence the stability of laboratory-scale displacements in which the mobility is unfavorable. Major emphasis is placed on analyzing the role of transverse dispersion in this process. The various flow patterns that can occur during fingering are shown as well as the composition history of the process during an unstable flood. For the process under study here, simulation results predict that the upstream side of the oil bank A extremely stable. Any fingers that form upstream of this front are unable to distort the stability of the oil bank. Some mechanisms for lateral finger movement in the core are explainer and the effect of discretization on simulating these movements is shown. Finally, the effect of transverse dispersion on flow in high permeability streaks is illustrated.


Title: Core Acquisition and Analysis for Optimization of the Prudhoe Bay Miscible-Gas Project

Authors: P.L. McGuire, Arco Alaska Inc.; A.P. Spence, F.I. Stalkup, M.W. Cooley, Arco E&P Technology

SPE Reservoir Engineering Volume 10, Number 2 May 1995 Pages 94-100

Copyright 1995. Society of Petroleum Engineers

Core data from a sidetrack well 250 ft from an old injection well showed intervals of excellent miscible-gas sweep, with miscible-flood residual oil saturations (ROS's), Sorm, of ˜5% PV. Less-well-swept intervals had intermediate Sorm values. Numerous intervals had not been contacted by miscible injectant (MI). Chromatographic analyses of the Dean-Stark core extracts quantified miscible-gas alteration of the oil and was especially valuable in the interpretation of intermediate oil saturations. Compositional reservoir simulations showed that high-permeability thief zones and a number of thin shales controlled sweep efficiency near the cored well


Title: Reservoir Description Detail Required To Predict Solvent and Water Saturations at an Observation Well

Authors: F.I. Stalkup, S.D. Crane, Arco E&P Technology SPE Reservoir Engineering Volume 9, Number 1 February

1994 Pages 35-43

Copyright 1994. Society of Petroleum Engineers

This paper describes the reservoir simulator analysis of an observation-well pilot test in the Prudhoe Bay miscible flood. It shows that 1-ft simulator layers and explicit representation of thin, discontinuous shales are required to predict solvent occurrences and log-derived water and solvent saturations at the observation well. The predictions show that solvent flows past the well in numerous tongues that are only a few feet thick.


Title: Performance Analysis and Optimization of the Prudhoe Bay Miscible-Gas Project

Authors: P.L. McGuire, SPE, Arco Alaska Inc., and F.I. Stalkup, SPE, Arco E&P Technology SPE Reservoir

Engineering Volume 10, Number 2 May 1995 Pages 88-93

Because EOR oil response at Prudhoe Bay has been difficult to measure directly, a number of different types of field measurements have been made to evaluate the miscible-flood displacement efficiency. These measurements include water- and solvent-injection profiles, logging data from an observation well, and single-well tracer test (SWTT) data. Despite ambiguity in these data, the measurements support the simulation and laboratory data and generally indicate that the Prudhoe Bay Miscible Gas Project (PBMGP) is performing well. The most useful EOR surveillance data have been the separator-gas-sample database, with =4,000 compositional analyses. Separator flash analysis and allocation programs use this database to infer EOR performance on the basis of produced solvent. Reservoir mechanisms that adversely affect the EOR process efficiency have been identified. The project has exceeded initial expectations in terms of solvent retained within the reservoir, which has favorable implications for solvent sweep efficiency. Procedures have been developed to use the field and simulation data to determine how the solvent should be allocated to the existing patterns and when the project should be expanded into new areas. These procedures are designed to maximize the value of the PBMGP.


Title: Displacement of oil by Solvent at High Water Saturation

Authors: Stalkup, F.I., Atlantic Richfield Co. SPE Journal Volume 10, Number 4 December 1970 Pages 337-348

Copyright 1970

Displacements of laboratory oils by propane in long, consolidated sandstone cores in the presence of high water saturations have shown that oil recoveries approaching 100 percent may be realized by continuous water-propane injection, even for oil saturations close to residual oil. However, it was often necessary to inject many pore volumes of solvent to attain this high a recovery. Initial oil saturations were established by injecting water and oil at a constant ratio into the porous medium containing residual oil to a waterflood until a steady state was obtained. Propane and water were then injected in the same fixed ratio to displace the oil. These and other experiments indicate that in the presence of a high water saturation only part of the presence of a high water saturation only part of the oil is flowable. Part resides in locations that are blocked by water, and the oil in these stagnant locations is not flowable. This nonflowable oil, it is believed, can be recovered by molecular diffusion into the flowing propane of a water-propane displacement. Values for the saturation of hydrocarbon that is contained in the stagnant locations and values for the ratio of the longitudinal hydrodynamic-dispersion coefficient to displacement velocity were determined at various water saturations in the test sandstones. The data suggest that rock wettability may influence the stagnant saturation and that stagnant oil saturations may not be as large in reservoir rocks as they are observed to be in laboratory sandstones. Mass transfer between the flowing solvent and hydrocarbon components in the stagnant saturation was expressed by a first-order rate expression. Rough values for the mass transfer coefficients for the propane-trimethylhexane hydrocarbon pair were estimated from experiments. Computations using these values for mass transfer coefficients indicate that experiments in laboratory-size cores may show much poorer displacement efficiency than that which might actually occur in the field.


Title: Predicting the Effect of Continued Gas Enrichment Above the MME on Oil Recovery in Enriched Hydrocarbon Gas Floods

Authors: Stalkup, Fred, ARCO Exploration and Production Technology SPE Annual Technical Conference and

Exhibition, 27-30 September 1998, New Orleans, Louisiana

Copyright 1998, Society of Petroleum Engineers

Gas enrichment can be an important optimization variable in hydrocarbon enriched gas drive floods. Slimtube experiments often show that oil recovery increases sharply up to the minimum miscibility enrichment (MME) and thereafter increases very little with further enrichment. However, there are physical reasons why oil recovery might continue to improve with increasing gas enrichment above the MME in a reservoir flood: 1) the gas becomes more viscous and more dense from mixing with oil, which improves sweepout, 2) a smaller lean-gas bank develops, which also may improve sweepout, and 3) richer gases may mix less deeply with oil into the multiphase region leaving less miscible flood residual oil behind.

All of these mechanisms are influenced by the physical gas-oil mixing that occurs in a reservoir flood. Unfortunately, a concern with commercial simulators is that numerical mixing or dispersion, which is artificial and non-physical, may dwarf the mixing from physical mechanisms and cause an unrealistic prediction of the effect of continued gas enrichment on additional recovery even if physical mechanisms such as molecular diffusion and dispersion are accounted for in the formulation of the simulator.

This paper investigates the effect of realistic levels of physical dispersion on any increase in recovery resulting from continued enrichment of hydrocarbon gas above the MME. It does this in simplified reservoir-scale cross sections by 1) minimizing numerical dispersion relative to the input physical dispersion by using two-point upstream weighting and a large number of grid blocks, and 2) by approximating longitudinal physical dispersion with numerical dispersion in single-point weighting simulations by making the grid blocks small enough to mimic the physical dispersivity that might prevail in a reservoir. It also attempts to provide insight into the error large grid blocks may cause when gas enrichment is studied with reservoir models.

The results of this study suggest that recovery may continue to improve significantly with enrichment above the MME and that this effect should not be overlooked when optimizing the enrichment of an enriched gas-drive flood. The results also suggest that extremely small grid blocks in the lateral direction may not be required to realistically assess the improvement in recovery with continued gas enrichment if the mixing from the viscous crossflow caused by alternate water and gas (WAG) cycles dominates the numerical mixing caused by moderate-size grid blocks.


Title: Sensitivity to Gridding of Miscible Flood Predictions Made With Upstream Differenced Simulators

Authors: Stalkup, F.I., Lo, L.L., Dean, R.H., ARCO Oil and Gas Co. SPE/DOE Enhanced Oil Recovery Symposium,

22-25 April 1990, Tulsa, Oklahoma

Copyright 1990, Society of Petroleum Engineers

This paper examines the sensitivity to gridding of first-contact miscible and three-component multicontact miscible condensing-gas drive predictions made with an upstream differenced simulator. These cross-section simulations are made for various reservoir descriptions and for models of increasing numbers of grid blocks. The largest models range from 5000 to 24,000 grid blocks. The paper examines gridding sensitivity when the coefficients of convective terms are evaluated by the single-point upstream method, and it also examines the utility of two-point upstream weighting and selectively refined initial gridding for moderating gridding sensitivity.

These simulations show the following behavior. For some problems with single-point upstream weighting, ultimate recovery changes monotonically with an increasing number of grid blocks. The change in recovery with increasing grid blocks can either be a decrease or an increase depending on the particular reservoir description, although decreasing recovery was the most common behavior for the reservoir descriptions examined here. Two-point upstream weighting and selectively refined initial gridding reduced, but didn't eliminate, this sensitivity. Some predictions appear to converge almost linearly with predictions appear to converge almost linearly with grid size to approximately the same answer in the limit of zero grid block size (i.e., infinite grid blocks) when the problem is worked in different ways, e.g., single-point weighting, two-point weighting, selectively refined initial gridding. Other problems, however, do not appear to be converging for the largest models that were feasible.

Addition of physical diffusion/dispersion of a magnitude that might occur in reservoirs didn't affect the gridding sensitivity for two of the three reservoir descriptions examined, at least not for grid sizes that were feasible. However, for one reservoir description, recoveries computed with and without physical diffusion/dispersion appear to be diverging physical diffusion/dispersion appear to be diverging with grid refinement.


Title: Effect of Gas Enrichment and Numerical Dispersion on Enriched-Gas-Drive Predictions

Authors: Stalkup, Fred L., Arco Oil and Gas Co.EOR SPE Reservoir Engineering Volume 5, Number 4 November

1990 Pages 647-655

Copyright 1990. Society of Petroleum Engineers

This paper examines the effect of gas enrichment in reservoir-scale enriched-gas-drive displacements through predictions made with a compositional simulator and the Peng-Robinson equation of state (PREOS). The calculations examine behavior for a classical three-component condensing-gas drive and for a 12-component reservoir-fluid characterization that predicts condensing/vaporizing-gas-drive behavior. The predictions also illustrate behavior for two simplified reservoir analogues: a homogeneous cross section with a low vertical/horizontal permeability ratio and a stratified cross section. An important feature of permeability ratio and a stratified cross section. An important feature of this study is that the impact of numeri-cal dispersion on the predictions is assessed through numerical sensitivity calculations. The simulations show that (1) numerical dispersion causes an abnormally large, erroneous, predicted increase in recovery with increasing gas enrichment and a predicted increase in recovery with increasing gas enrichment and a predicted incremental recovery over waterflooding that could be too large predicted incremental recovery over waterflooding that could be too large by as much as a factor of two; (2) the most realistic predictions are obtained by extrapolating recoveries to a gridblock size of zero, even though the extrapolation may be imprecise and the degree of convergence to the correct answer is unknown; (3) numerical dispersion causes too large a predicted increase in recovery with gas enrichment beyond the critical enrichment; and (4) calculated oil recovery vs gas enrichment for the 3-and 12-component fluid characterizations studied is qualitatively similar for injection gases that give displacements ranging from highly immiscible to essentially first-contact miscible (FCM), although absolute differences in incremental recovery are sometimes as large as I to 2% of original oil in place (OOIP).


Title: Displacement Behavior of the Condensing/Vaporizing Gas Drive Process

Authors: Stalkup, F.I., ARCO Oil and Gas Co. SPE Annual Technical Conference and Exhibition, 27-30 September

1987, Dallas, Texas

Copyright 1987, Society of Petroleum Engineers

There is mounting evidence for some reservoir fluids that phase behavior in condensing-gas drives departs substantially from traditional concepts deduced for three-component fluids and that transition-zone compositions are established by a condensing/vaporizing mechanism rather than by condensation alone. To what extent does displacement behavior depart from traditional concepts as well and what is the significance of any departures? This paper addresses these questions through a series of compositional simulations for displacement in a one-dimensional slim-tube.

The simulations show that displacement behavior for a reservoir fluid does not depart substantially from traditional condensing-gas drive concepts for three-components even though the transition-zone building mechanism is one of condensation/vaporization. They show that when injection gas enrichment exceeds a critical value, displacement behavior of the reservoir fluid becomes miscible-like in the following important respects: 1) recovery is essentially 100% after one pore volume of injection in the limit of no dispersion, and 2) for a realistic level of dispersion, recovery at 1.2 pore volumes injected is insensitive to both relative permeability and relative permeability end-point saturation. Also, as with traditional concepts, the critical enrichment can be determined from slim-tube displacements by finding the point of breakover in a plot of oil recovery at 1.2 PV of injection vs. gas enrichment. However, with the reservoir oil, gases enriched above the critical value show a converging/diverging type of phase behavior on a pseudoternary diagram, and they leave a residual oil saturation, both of which are contrary to traditional concepts. The magnitude of the residual oil saturation depends primarily on mixing caused by diffusion/dispersion and should be relatively small, less than about 5% PV, in reservoir floods and even less in slim-tube displacements.

All the simulations were highly sensitive to the number of grid blocks used to model the slim-tube. This effect must be accounted for when simulated slim-tube behavior is compared with experiments, and it must be addressed in reservoir simulations. Simulations of 20% HCPV enriched-gas slugs driven by water show that a very high level of mixing shifts the point of optimum solvent enrichment to higher values. Numerical dispersion will cause this shift, even in simulations with as many as 100 grid blocks representing displacement length. Whether or not physical dispersion in the reservoir is great enough to cause it is an unanswered question.


Title: USE OF TIME-LAPSE LOGGING TECHNIQUES IN EVALUATING THE WILLARD UNIT CO2 FLOOD MINI-TEST

Authors: Stalkup, F.I., ARCO Oil and Gas Co. SPE Annual Technical Conference and Exhibition, 27-30 September

1987, Dallas, Texas

Copyright 1987, Society of Petroleum Engineers

This paper describes how compensated neutron and pulsed neutron logs were used to monitor performance pulsed neutron logs were used to monitor performance of a tertiary recovery minitest of CO2 miscible flooding. The paper contains (1) a description of procedures used to take and interpret the logs, procedures used to take and interpret the logs, (2) a discussion of the significance of the log responses, and (3) a discussion of the accuracy of calculated saturation changes.

The experiment was run in the San Andres dolomite formation in the Willard Unit, Wasson field. Logs were taken in an observation well, completed with unperforated steel casing, and located 100 ft from the CO2 injector. Water was injected first to thoroughly waterflood the region near the observation well. This was followed by injection of CO2 and water in small, alternate slugs. Logs were taken regularly during both the waterflood and the CO2 flood.


Title: A METHOD FOR PROJECTING FULL-SCALE PERFORMANCE OF CO2 FLOODING IN THE WILLARD UNIT

Authors: Bilhartz, H.L., Charlson, G.S., Stalkup, F.I., Miller, C.C., Atlantic Richfield Company SPE Symposium on

Improved Methods of Oil Recovery, 16-17 April 1978, Tulsa, Oklahoma

Copyright 1978, American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

A non-producing CO2 flood tertiary recovery test was recently completed in the Willard Unit of Wasson Field. Flood responses during waterflood and alternate injection of CO2 and water were monitored at a logging observation well using compensated neutron and pulsed neutron logs. A pressure core was taken to measure residual oil saturations at the test conclusion.

The overall objective of the testing was to obtain information for evaluating the potential for full-scale CO2 flooding in the unit. Our method for making this evaluation involves: (1) defining CO2 flood displacement efficiency and representing this efficiency in a miscible flood reservoir simulator; (2) defining a representative average reservoir description; and (3) projecting full-scale CO2 flood performance with the simulator. The paper provides a performance with the simulator. The paper provides a status report on progress to assess CO2 flooding potential for the Willard Unit in this manner. potential for the Willard Unit in this manner


Title: A Laboratory Investigation of Miscible Displacement by Carbon Dioxide

Authors: Rathmell, J.J., Stalkup, F.I., Hassinger, R.C., Atlantic Richfield Co. Fall Meeting of the Society of Petroleum

Engineers of AIME, 3-6 October 1971, New Orleans, Louisiana

Copyright 1971 American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

We have conducted displacements of reconstituted reservoir fluids in Boise outcrop sandstone cores of 6 to 42.5 ft in length using CO2 at various pressures. Our studies indicate that a miscible displacement may be achieved by CO2 injection at pressures well below those necessary when methane is the injection fluid. Miscibility by CO2 is generated through multiple contact equilibria in which the CO2 is progressively enriched with intermediates progressively enriched with intermediates (ethane through hexane) from the oil.

The miscibility pressure for CO2 and a given reservoir fluid is difficult to determine because CO2 exhibits highly efficient swelling and vaporization of the oil. We also found it impractical to operate below the rates where differences in density between displaced and displacing fluids prevent viscous fingering in vertical cores. We were able to define the miscibility pressure using the anticipated increasing recovery as a function of core length in miscible displacements in combination with effluent fluid visual cell observations and chromatographic data.


Title: Using Phase surfaces to Describe Condensing-Gas-Drive Experiments

Authors: Stalkup, Fred I., Junior Member AIME, The Atlantic Refining Co., Dallas, Tex. SPE Journal Volume 5,

Number 3 September 1965 Pages 184 - 185

Copyright 1965

Vapor-liquid phase equilibrium experiments have been conducted in a static equilibrium cell on mixtures of a light, 450 API stock-tank gravity reservoir fluid and a rich hydrocarbon gas containing approximately 55 mole per cent of intermediate hydrocarbons. Both a pressure-vs-composition study of the gas and a simulated reservoir fluid, and a multiple-batch contact simulation of the condensing-gas-drive oil recovery process were performed. In the latter experiments equilibrium gas and liquid compositions were analyzed. Also, conventional, "condensing-gas-drive", long-tube displacement experiments of the reservoir fluid and gases of various richness were performed. The results of these experiments could not be satisfactorily interpreted by the conventional pseudo-ternary-diagram representation of multicomponent phase behavior. The results seem to be explained better by considering a bubble-point surface and a dew-point surface joined in a plait-point locus. Portions of the plait-point locus cannot be "seen" directly by the rich hydrocarbon gas because of curvature of the dew-point surface. In such a system, continuous injection of the rich gas over stationary reservoir fluid might form a zone of contiguously miscible compositions from pure rich gas to pure reservoir fluid by: (1) saturating the reservoir fluid with injected gas to the bubble-point surface; (2) creating by mass transfer with fresh injected gas a path of contiguously miscible compositions along the bubble-point surface to the plait-point locus; and (3) creating by mass transfer with additional injected gas a path of gas compositions along the dew-point surface up to the point where direct miscibility results between dew-point fluid and the injected rich gas.


Title: Status of Miscible Displacement

Authors: Stalkup Jr., Fred I., ARCO Oil and Gas Company Journal of Petroleum Technology Volume 35, Number 4

April 1983 Pages 815-826

Copyright1983. 1982

Copyright 1982, Society of Petroleum Engineers

Methods for miscible flooding have been researched and field tested since the early 1950's. This paper reviews the technical state of the art and field behavior to date for the major miscible flood processes: first-contact miscible, rich-gas drive, vaporizing-gas drive, and carbon dioxide flooding. Important technological areas selected for review include phase behavior and miscibility, sweepout, unit displacement efficiency, and process design variations. Carbon dioxide flood technology is emphasized, and several technical issues are identified that still need to be resolved. Rules of thumb and ranges of conditions are discussed for applicability of each process. A comparison is made of the incremental recovery and solvent slug effectiveness observed in field trials of the different processes. From the limited data available, processes. From the limited data available, there is no clear-cut evidence that field results on average and for a given slug size have been appreciably better or poorer for one process compared with another.


Title: Carbon Dioxide Miscible Flooding: Past, Present, And Outlook for the Future

Authors: Stalkup, F.I., Atlantic Richfield Co. Journal of Petroleum Technology Volume 30, Number 8 August 1978

Pages 1102-1112

Copyright 1978

This paper gives an overview of the carbon dioxide miscible-flooding process, reviews current technology, discusses past and current field process, reviews current technology, discusses past and current field testing, and assesses the state-of-the-art. Carbon dioxide sources are identified and evaluated. Potential oil recovery, producing rates, and future outlook are projected.


Title: Development of Reservoir Descriptions To Aid in Design of EOR Projects

Authors: Chopra, A.K., Stein, M.H., Ader, J.C., Amoco Production Co. SPE Reservoir Engineering Volume 4,

Number 2 May 1989 Pages 143-150

Copyright 1989. Society of Petroleum Engineers

A technique was developed to obtain reservoir descriptions to aid in the design of EOR projects. This technique incorporates the reservoir performance during primary and secondary processes and the geological, petrophysical, and pressure-transient data. The application of this technique is illustrated for a San Andres formation reservoir.


Title: Prediction of Performance of Miscible-Gas Pilots

Authors: Chopra, Anil K., Stein, Michael H., Dismuke, Carl T., Amoco Production Co. Journal of Petroleum

Technology Volume 42, Number 12 December 1990 Pages 1564-1572

Copyright 1990. Society of Petroleum Engineers

A model was developed to predict field performance of miscible-gas injection projects in oilwet reservoirs. The model represents a vaporization and/or liquid extraction multiple-contact-miscible (MCM) process by a stabilized-contact process by a stabilized-contact miscible process. A critical component of the model is the inclusion of a solvent relative permeability (SRP), different from the oil relative permeability, in the presence of a final oil saturation.

An example match of a miscible gas injection pilot is shown with the new model. Satisfactory matches of both production and injection well performance data with model predictions were obtained. The pilot predictions were obtained. The pilot reservoir description was not changed to match miscible-gas flood performance. The new model was also used performance. The new model was also used to match field-performance data of other pilots using the same procedure. Although not shown in this procedure. Although not shown in this paper, matches of similar quality paper, matches of similar quality were obtained for all the other pilots.


Polymer EOR

Title: Estimating Field-Scale Micellar/Polymer Performance

Authors: Giordano, R.M., ARCO Oil and Gas Co. SPE Annual Technical Conference and Exhibition, 27-30

September 1987, Dallas, Texas

Copyright 1987, Society of Petroleum Engineers

A study has been completed on the effects of pattern type, micellar slug size, heterogeneity, and process timing on micellar/ polymer flooding. In designing a field-scale enhanced recovery process, one generally knows the laboratory-scale performance of the process, the area of reservoir to be developed, its physical properties, and the number of wells that can be afforded. With these "givens", a simple model has been developed for deter-mining the optimum pattern type and optimum micellar slug size as a function of the "field-scale capillary number", the Dykstra-Parsons coefficient, and the discount rate.

Results show that, on an equal-area-per-well basis, five-spot and staggered line drive patterns are favored over seven- and nine-spot configurations. The optimum slug size for a homogeneous five-spot was found to be the amount required to satisfy about 90% of the surfactant adsorption requirement of the reservoir. The optimum slug size decreased with increasing heterogeneity. Oil recovery in low-permeability fields or those in which the well-spacing is large can be significantly enhanced by utilizing a surfactant whose interfacial tension against oil is less than 10(-3) dynes/cm.


Combustion EOR

Title: A Sensitivity Study of the Effect of Parameters on Results From an In-Situ Combustion Simulator

Authors: Anis, M., Mobil R and D Corp.; Hwang, M.K., Mobil R and D Corp.; Odeh, A.S., Mobil R and D Corp. SPE

Journal Volume 23, Number 2 April 1983 Pages 259-264

Copyright1983

A study of the sensitivity of results from an in-situ combustion simulator to key parameter variations was made. The model was based on the finite-difference method of solution and accounted for the kinetics of the combustion process. The parameters were block size, dimensionality of the model, number of reactions, activation energy, reaction constant, and injection rate. About 50 dry-combustion simulation runs were made using the model in one-, two-, and three-dimensional (1D, 2D, and 3D) modes. The chemical properties for a heavy oil were used. In general, runs were carried out properties for a heavy oil were used. In general, runs were carried out for 6,000 days. The output results were cumulative oil production, oxygen consumption, peak temperature, injection bottomhole pressure (BHP), WOR, GOR, heat release from reactions, fuel consumptions, and saturation distribution. The results were most sensitive to the flow convection parameters, such as block size and dimensionality. Kinetic parameter effects were not as significant as previously thought. Moreover, the investigation identified practical difficulties in running a kinetic-based model. Numerical distortion of the convection effects with large grid blocks limits the utility of such models. A brief discussion of a possible method to overcome some of the difficulties is given.


Title:-An In-Situ Combustion Process Simulator With a Moving-Front Representation

Authors:-Hwang, M.K., Mobil Research and Development Corp.; Jines, W.R., Mobil Research and Development Corp.;

Odeh, A.S., Mobil Research and Development Corp. SPE Journal Volume 22, Number 2 April 1982 Pages

271-279

Copyright1982

This paper describes THERMS, a new three-phase, black-oil simulator for in-situ combustion processes. The model also can simulate steam and hot-water injection operations. To simulate field-scale in-situ combustion projects, THERMS uses experimental data obtained from laboratory combustion-tube runs. Detailed kinetics and thermodynamic relations are not used. The model treats the burning zone as a moving front. The front is viewed not only as a moving heat source, but also as a displacement pump enhancing oil flow. This approach results in a new algorithm. The model has been designed with strongly field-oriented features. Its utility is illustrated by a history-matching study of the South Belridge, CA, dry-combustion pilot test.


Title: Factorial Design Analysis of Wet-Combustion Drive

Authors: SAWYER, D.N., COBB, W.M., STALKUP, F.I., BRAUN, P.H., ATLANTIC RICHFIELD CO. SPE Journal

Volume 14, Number 1 February 1974 Pages 25-34

Copyright 1974

This paper illustrates the application of a statistical experimental design technique (factorial design) to the study of a computer model of a physical process (the wet-combustion drive). physical process (the wet-combustion drive). Factorial design has been used successfully for many years in experimental work to allow investigators to study systematically and efficiently the interactions of important variables and their effects on physical processes. It can also be applied to great advantage processes. It can also be applied to great advantage to computer models of physical processes. The mathematical model in this illustration was programmed to simulate the wet-combustion process programmed to simulate the wet-combustion process in a previously waterflooded confined five-spot. The model couples basic energy and mass balance equations to approximate heat and fluid-flow phenomena. Application of the factorial design phenomena. Application of the factorial design technique to this computer model has allowed us to study individually and collectively, in a relatively short time, the effects that nine important variables exert on the economics of this process. These nine variables are measures of time, reservoir pressure, heat loss, oil burned as fuel, waterflooded residual oil, steam front sweep, oil bank sweep, air co st, and oil price. The final result is a simple equation containing these variables that can be used by the reservoir analyst quickly to screen reservoirs as candidates for the wet-combustion process and perform a sensitivity analysis to determine how perform a sensitivity analysis to determine how uncertainties in the variables will affect the economics.


Chem EOR

Title: Comparison of Simulation and Experiments for Compositionally Well-Defined Corefloods

Authors:Giordano, R.M., Salter, S.J., ARCO Oil and Gas Co. Gas EOR rem SPE Enhanced Oil Recovery

Symposium, 15-18 April 1984, Tulsa, Oklahoma

Copyright 1984 Society of Petroleum Engineers AIME

The mechanisms which affect the efficiency of chemical flooding processes have been the focus of considerable research and speculation in recent years. One method to identify these mechanisms is the comparison of carefully conducted experiments with results generated using a mathematical model (simulator). In this paper we report both experimental and simulation results for II-, II+, and three-phase systems run so that the entire flood remains on a single phase diagram. In order to do this rigorously, we have used simple systems in which the complexities of non-pseudoternary behavior are absent. We simulated experimental core floods using a modified version of INTERCOMP's Chemical Flooding Simulator CFTE and tested the sensitivity of the results to a variety of process mechanisms. We also employed a method-of-characteristics solution to independently check the simulator. In doing so we extended the method-of-characteristics to three-phase, multicomponent flow in porous media. Our major objective is to show the interactions among the phase behavior, fluid flow, mixing, and mobility mechanisms which are present in chemical flooding processes.

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