Our Publications
A few publications by PetroTel's experts
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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
Fluid Characterization
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
Title: Effect of EOS Characterization on Predicted Miscibility Pressure
Authors:
F. Stalkup and H. Yuan, SPE, PetroTel Inc.
SPE Annual Technical Conference and Exhibition, 9-12 October 2005, Dallas, Texas
Copyright 2005. Society of Petroleum Engineers
This paper illustrates the above remarks for three different reservoir fluids that have different amounts of PVT data to tune the EOS against. These examples show that what appear to be equally acceptable EOS characterizations with regard to PVT data predictions can predict differences in miscibility pressure as much as 500 to 1000 psia. In an example simulation in a heterogeneous reservoir cross section, these differences in EOS characterization caused 7 to 22% differences in predicted incremental recovery.
Title: Fluid Characterization for Miscible Gas Floods
Authors:
Hua Yuan, Anil Chopra, Vineet Marwah, and Fred Stalkup, SPE, PetroTel Inc.
SPE Annual Technical Conference and Exhibition, 21-24 September 2008, Denver, Colorado, USA
Copyright 2008. Society of Petroleum Engineers
Title: Effect of Gas Enrichment and Numerical Dispersion on Enriched-Gas-Drive Predictions EOR
Authors:
Stalkup, Fred L., Arco Oil and Gas Co.
SPE Reservoir Engineering Volume 5, Number 4 November 1990 Pages 647-655
Copyright 1990. Society of Petroleum Engineers
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
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.
Gas Condensate Reservoir
Title: Predicting Gas Condensate Well Productivity Using Capillary Number and Non-Darcy Effects
Authors:
G. Narayanaswamy, G.A. Pope, M.M. Sharma, The University of Texas at Austin; M.K. Hwang, R.N. Vaidya, Mobil E&P Technical Center
SPE Reservoir Simulation Symposium, 14-17 February 1999, Houston, Texas
Copyright 1999, Society of Petroleum Engineers
Title: Estimation of Condensate Dropout Effects on Well Productivity as Skin Change with Multiplicative Interactions Among Skin Components
Authors:
Hwang, M.K., Odeh, A.S., Mobil R & D Corp. SPE 29894-MS 1995
Middle East Oil Show, 11-14 March 1995, Bahrain
Copyright 1995, Society of Petroleum Engineers
The new equation developed here has significant implications in various engineering analyses. The conventional method can grossly overestimate well deliverability, if the total skin value is computed from individual components. Conversely, when an individual component (such as Sm) is back-calculated from the total skin obtained from pressure transient analysis, the conventional method can grossly overestimate Sm. Also, this new equation can be used to predict simulation impacts of different wellbore description and of adjustments made in permeability distributions and skin components during history matching.
Title: Proof of the Two-Phase Steady-State Theory for Flow Through Porous Media
Authors:
Chopra, Anil K., Amoco Production Co.; Carter, Robert D., Amoco Production Co.
SPE Formation Evaluation Volume 1, Number 6 December 1986 Pages 603-608
Copyright 1986. Society of Petroleum Engineers
Gas Reservoir Engineering
Title: The Importance of Water Influx in Gas Reservoirs
Authors:
R.G. Agarwal, R. Al-Hussainy, H.J. Ramey, Jr., Texas A&M U.
Journal of Petroleum Technology Volume 17, Number 11 November 1965 Pages 1336-1342
Copyright 1965 Society of Petroleum Engineers
The manner of estimating water-drive gas reservoir recovery can vary considerably. Examples are: the steady-state method, the Hurst modified steady-state method, and various unsteady-state methods such as those of van Everdingen-Hurst, Hurst, and Carter-Tracy. The Carter-Tracy water influx expression was used in this study.
In certain cases, it appears that gas recovery can be increased significantly by controlling the production rate and manner of production. For this reason, the potential importance of water influx in particular gas reservoirs should be investigated early to permit adequate planning to optimize the gas reserves.
Title: A Method for Selecting Potential Infill Locations in the East Texas Cotton Valley Tight Gas Play
Authors:
Tison, Joel K., Agarwal, Ram G., Rosepiler, Michael J., Schlottman, Bernard W., Amoco Production Co.
SPE Annual Technical Conference and Exhibition, 26-29 September 1982, New Orleans, Louisiana
Copyright 1982, Society of Petroleum Engineers of AIME
Critical reservoir and fracture parameters are investigated by determining each parameter's effect on the incremental reserves from an infill well. The most important parameters are: formation flow capacity, hydrocarbon pore volume, fracture length, and pay continuity. These parameters are used to obtain simulated rate data for well groups from a tight gas reservoir simulator. Recoverable gas is determined from a plot of the simulated data as scalar curves relating well rate and cumulative production data to tine, normalizing the curves to the above critical parameters. Potential infill reserves are assessed for East Texas Cotton Valley wells using the results from the above curves in an expression for incremental infill reserves. The variation of incremental reserves with fracture length for varying permeabilities is investigated to obtain an economic limit on incremental reserves for a general area and to deter-mine the range of permeabilities justifying reduced well spacing.
This two-well analysts approach assumes separate, non-interfering drainage blocks and may introduce error in high permeability areas. Moreover, this analysis technique assumes no time delay in drilling the infill well on a unit. Static pressure measurements in the first infill wells must be obtained to evaluate potential interference as well as gain experience in potential interference as well as gain experience in drainage radii for the original wells on a unit.
Title: High Velocity Gas Flow Effects in Porous Gas-Water System
Authors:
Grigg, Reid B., New Mexico Petroleum Recovery Research Center; Hwang, Myung K., Mobil E & P Technology Center
SPE Gas Technology Symposium, 15-18 March 1998, Calgary, Alberta, Canada
Copyright 1998, Society of Petroleum Engineers Inc
Log Interpretation
Title: USE OF TIME-LAPSE LOGGING TECHNIQUES IN EVALUATING THE WILLARD UNIT CO2 FLOOD MINI-TEST
Authors:
Charlson, G.S., Bilhartz Jr., H.L., Stalkup, F.I., 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.
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.
Reservoir Characterization
Title: The Effects of Permeability Variations on Flow in Porous Media
Authors:
Giordano, R.M., Salter, S.J., Mohanty, K.K., ARCO Resources Technology
SPE Annual Technical Conference and Exhibition, 22-26 September 1985, Las Vegas, Nevada
Copyright 1985, Society of Petroleum Engineers
Although only laboratory-scale systems are studied, the concepts and insights which we present can help interpret larger-scale systems. present can help interpret larger-scale systems. The results can be used not only to judge the degree of detail needed to simulate permeability variations for a given process, but also to gauge the robustness of a process to permeability variations.
Title: Permeability Variation in a Sandstone Barrier Island-Tidal Channel-Tidal Delta Complex, Ferron Sandstone (Lower Cretaceous), Central Utah
Authors:
Stalkup, F.I., Ebanks Jr., W.J., ARCO Oil and Gas Co.
SPE Annual Technical Conference and Exhibition, 5-8 October 1986, New Orleans, Louisiana
Copyright 1986, Society of Petroleum Engineers
Fifteen outcrop exposures representing different vertical sections of the complex were examined to determine the lithofacies present and their distribution. Horizontal cores approximately six in. long and one in. in diameter were taken at selected locations for permeability measurements. permeability measurements. These observations and measurements give the following picture of permeability structure in the sediments of this particular complex. Permeability heterogeneity occurs on several size scales. On the largest scale, crossbedded, burrowed, rippled, and shally lithofacies are distinguished for characterizing gross permeability layering. These permeability units are continuous permeability layering. These permeability units are continuous over distances of at least 500 to 1000 ft in the seaward direction and probably are continuous over much greater distances in the along-shore direction. Some lithofacies did not define independent permeability units, however, and had to be combined with vertically adjacent facies to form a unit. On an intermediate scale, permeability sublayers on the order of 2 to 4 ft thick occur within some of the units. The lateral extent of these sublayers was not determined. On a small scale within the sublayers, permeability variation appears to be random for samples that are permeability variation appears to be random for samples that are separated by at least 6 in., the minimum sample separation investigated. Estimates are given in the paper for the magnitude of permeability contrast between permeability units, the lateral variation of mean permeability within a unit, and the permeability contrast between sublayers within a unit.
Permeability of the rocks in outcrops was compared to that of Permeability of the rocks in outcrops was compared to that of similar rocks in the same stratigraphic unit in a nearby well. Permeability contrasts among lithofacies are greater in the Permeability contrasts among lithofacies are greater in the subsurface than in the outcrops because of surface weathering, but the vertical arrangement of statistically different permeabilities is similar in the two situations.
Title: Scaleup of Geological Facies for Multiphase Flow Simulation
Authors:
Tambe, D.E., Chopra, A.K., Arco Exploration and Production Technology
SPE Asia Pacific Conference on Integrated Modelling for Asset Management, 23-24 March 1998, Kuala Lumpur, Malaysia
Copyright 1998, Society of Petroleum Engineers
This paper describes a steady-state methodology to generate effective multiphase flow functions (relative permeability and capillary pressure) and pseudo functions for reservoir models consisting of multiple geologic facies. The generated effective flow functions capture the variations in geologic facies and petrophysical heterogeneities that control reservoir performance. The technique can be used to scale up complex geologic models for reservoir simulators. This steady-state approach is significantly faster than other techniques requiring multiphase flow simulations.
The technique was applied to scale up a realistic 3-D reservoir description of a complex fluvio-deltaic sandstone reservoir. The generated effective flow functions were used successfully to reproduce truth case' performance predictions (oil recoveries, pressure profiles, and water production) for a quarter 5-spot and a quarter 9-spot pattern. The generated effective flow functions depend largely on the permeability distribution, the spatial distribution of geologic facies, and the relative proportions of the geologic facies in the reservoir model.
Title: Connectivity-Constrained Upscaling
Authors:
Gajraj, Allyson, Lo, Tak Sing, Chopra, Anil K., ARCO Exploration and Production Technology
SPE Annual Technical Conference and Exhibition, 5-8 October 1997, San Antonio, Texas
Copyright 1997, Society of Petroleum Engineers
The new upscaling approach is applied to a gas reservoir system. Traditional upscaling techniques, such as a pressure solver, are also applied to the fine scale reservoir description and the different sets of upscaled grids are flow simulated -- along with the fine scale description. The results of this new upscaling approach are shown to be significantly more accurate in providing an upscaled grid system which more closely approximates the simulation behavior of the fine scale grid.
This methodology has been shown to be applicable to the case of primary recovery from gas reservoirs and, while it has not been tested with more complex recovery mechanisms such as waterflooding, the theory is robust enough that it should be generally applicable as an upscaling technique in which reservoir connectivity is an issue.
Title: Application of Wavelet Transforms to Reservoir Data Analysis and Scaling
Authors:
Panda, M.N., Mosher, C., Chopra, A.K., ARCO Exploration and Production Technology
SPE Annual Technical Conference and Exhibition, 6-9 October 1996, Denver, Colorado
Copyright 1996, Society of Petroleum Engineers
Wavelet transforms provide a multiresolution framework for data representation. They are a family of orthogonal basis functions that separate a function or a signal into distinct frequency packets that are localized in the time domain. Thus, wavelets are well suited for analyzing non-stationary data. In other words, a projection of a function or a discrete data set onto a time-frequency space using wavelets shows how the function behaves at different scales of measurement. Because wavelets have compact support, it is easy to apply this transform to large data sets with minimal computations.
We apply the wavelet transforms to one-dimensional and two-dimensional permeability data to determine the locations of layer boundaries and other discontinuities. By binning in the time-frequency plane with wavelet packets, permeability structures of arbitrary size are analyzed. We also apply orthogonal wavelets for scaling up of spatially correlated heterogeneous permeability fields.
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
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
Title: Reservoir Modeling Using Scale-Dependent Data
Authors:
M.N. Panda, C. Mosher, A.K. Chopra, Arco E&P Technology
SPE Journal Volume 6, Number 2 June 2001 Pages 157-170
Copyright 2001. Society of Petroleum Engineers
Current geostatistical methods map lithofacies, porosity, and permeability on a network of grid nodes called the geologic modeling cells. Pseudopoint properties that assimilate information from all available data are modeled onto model cells using one of several available conditional-simulation techniques. Some methods attempt to combine data with varying support, and data with multiple-scale support, through simple correlations. For example, one approach to incorporate geophysical data is to use a direct transform of the seismic signal to rock properties through a linear regression or crossplot. Reservoir models built using such linear correlations tend to be case-specific with little generality.
This paper presents a method for identifying the impact of multiscale data (data that measure average property over multiple-flow units) on reservoir modeling. It examines the information about the reservoir system each data type carries, for example, what fraction of core scale variability is captured by well-log data. We also present a consistent method for integrating multiscale data. Through a series of numerical simulations, we show the impact of reservoir-property heterogeneity on the fluid-flow performance.
Title: Evaluation of Fractal Models To Describe Reservoir Heterogeneity and Performance
Authors:
G. Perez, A.K. Chopra, Arco E&P Technology
SPE Formation Evaluation Volume 12, Number 1 March 1997 Pages 65-72
Copyright 1997. Society of Petroleum Engineers
The fractal model of fractional Brownian motion (FBM) in the horizontal direction, having same intermittency exponent as for fractional Gaussian noise (FGN) in the vertical direction, is not supported by log observations in horizontal wells. Fractal character of core and log data of vertical wells is similar. The incremental WAG recovery response compared to waterflooding response is more sensitive to reservoir heterogeneity. Scale-up experiments indicate that spatial correlation structure of reservoir properties may be different at different scales.
Results of this paper will he useful for evaluation of infill drilling, and design, selection, and optimization of an EOR process. The proposed techniques also provide a framework to quantify uncertainty in reservoir performance.
Title: Ability of Geostatistical Simulations To Reproduce Geology: A Critical Evaluation
Authors:
Hand, J.L., ARCO Alaska Inc.; Yang, Chung-Tien, Chopra, A.K., ARCO E&P Technology; Moritz Jr., A.L., ARCO Alaska Inc.
SPE Annual Technical Conference and Exhibition, 25-28 September 1994, New Orleans, Louisiana
Copyright 1994, Society of Petroleum Engineers
The base geological description was generated using a hand drawn map of the geological facies associations within a 3-D model area in a fluvio-deltaic environment. The average values of porosity and permeability were assigned to the respective facies associations. A second description was generated using sequential gaussian simulation by honoring the porosity and permeability well data, the corresponding vertical variograms, and the inferred lateral variograms. A third description was generated using sequential indicator simulation to distribute porosity and permeability instead of sequential gaussian simulation. Both of these simple geostatistical descriptions were not constrained by explicit geological facies association information. A final more complex geostatistical description was generated in which the underlying geological framework of facies association was first simulated using truncated gaussian simulation and then the porosity and permeability were distributed within each facies association using sequential gaussian simulation. All of the fine scale descriptions were compared in detail and scaled up to large grid blocks appropriate for flow simulation using a pressure solver.
A comparison of the 3-D hand drawn facies association map with the one computed using truncated gaussian simulation showed that the hand drawn map contained less variations than the geostatistical facies association map when conditioned to the same well data. Comparison of the fine scale porosity and permeability maps showed that the distribution of the average values of porosity and permeability in the 3-D hand drawn facies association map failed to reproduce the complex texture of the rocks giving a considerably more uniform distribution of these attributes. It was found that distributing porosity and permeability geostatistically without the influence of explicit facies association information significantly reduced the effective control on the distribution of these attributes, resulting in a more continuous distribution of porosity and permeability than that obtained when facies association information was used. Comparison of the fine scale permeability distributions to those obtained after scaleup showed that the pressure solver maintained the major permeability features apparent in the fine scale distribution which were important to reservoir performance. The influence of these description techniques on reservoir performance was compared using a fluid flow simulator.
Title: Geostatistical Integration of Geological, Petrophysical, and Outcrop Data for Evaluation of Gravity Drainage Infill Drilling at Prudhoe Bay
Authors:
Hand, J.L., Moritz Jr., A.L., ARCO Alaska Inc.; Yang, Chung-Tien, Chopra, A.K., ARCO E&P Technology
SPE Annual Technical Conference and Exhibition, 25-28 September 1994, New Orleans, Louisiana
Copyright 1994, Society of Petroleum Engineers
Title: Evaluation of Geostatistical Techniques for Reservoir Characterization
Authors:
Chopra, A.K., ARCO Oil and Gas Co.; Severson, C.D., Carhart, S.R., ARCO Alaska, Inc.
SPE Annual Technical Conference and Exhibition, 23-26 September 1990, New Orleans, Louisiana
Copyright 1990, Society of Petroleum Engineers
Conventional and geostatistical reservoir characterization techniques are compared in this paper. Field data from about 50 wells are used in this evaluation. Interwell properties are computed using conventional and properties are computed using conventional and geostatistical techniques, cross-validated, and compared. Histograms show there are no geographically distinct populations requiring separate modeling. Experimental populations requiring separate modeling. Experimental variograms identify the scales of variability of the reservoir properties and the existence of preferential directions of properties and the existence of preferential directions of maximum and minimum variability. Variogram models are fitted to the experimental correlations.
The results of this work indicate that the success of any technique is a function of the geological environment, selection of proper reservoir parameters for that environment, an adequate number of samples, an appropriate sample spacing, and most importantly, the correct application of the technique. Geostatistical techniques have more potential to incorporate the underlying correlation present in the data in the final analysis.
Title: Reservoir Descriptions Via Pulse Testing: A Technology Evaluation
Authors:
Chopra, A.K., Amoco Production Co.
International Meeting on Petroleum Engineering, 1-4 November 1988, Tianjin, China
Copyright 1988, Society of Petroleum Engineers
The integrated approach is applied to a pulse test pilot completed in a San Andres reservoir. The usefulness of pulse testing is found to be highly reservoir specific. Pulse test data alone are not sufficient to derive reservoir descriptions for multilayer heterogeneous reservoirs and must be used in conjunction with geological, petrophysical, and single well pressure transient data. Pulse testing may not provide an adequate definition of vertical layer heterogeneities for tertiary miscible gas performance predictions and can be used only to refine the definition of high speed layers which control gas cycling in a tertiary miscible gas process. The pulse test derived reservoir description may be adequate for waterflooding predictions under certain situations. For primary depletion predictions, single well pressure transient data are sufficient when coupled with geological and petrophysical data. The integrated approach to evaluate pulse testing is recommended before actually conducting pulse tests in the field.
Reservoir Management
Title: A Streamline Based Reservoir Management Workflow to Maximize Oil Recovery
Authors:
Ronald M. Giordano, SPE, Shekhar Jayanti, SPE, Anil Chopra, SPE, Hua Yuan, SPE, Kazuhiro Asakawa, SPE, PetroTel Inc. Ali Suleimani, SPE, Ali Gheithy, SPE, and Clement Edwards, Petroleum Development Oman
SPE/EAGE Reservoir Characterization and Simulation Conference, 28-31 October 2007, Abu Dhabi, UAE
Copyright 2007. Society of Petroleum Engineers
This paper presents a robust and proven reservoir management workflow that can be used to evaluate short to medium term development scenarios proposed by production technologists. Traditionally, reservoir engineers make medium to long term field development decisions based on complex reservoir models, while production technologists make short term well level decisions based on operational data. As a result, the reservoir engineers and production technologists frequently work independent of each other. This paper provides the workflow and techniques that enable reservoir engineers and production technologists to work in an integrated manner and thereby increase production and recovery in a mature field.
An integrated reservoir management workflow was developed that can help not only the reservoir engineer to understand the reservoir dynamics, but also the production technologist to evaluate everyday production opportunities. This evaluation is brought about by integrating streamlines from finite-difference simulations, well performance data, and novel performance diagnostic plots. This approach was successful in developing a dynamic model for the Lekhwair field. The proposed workflow and applications provide efficient ways to maximize oil recovery in a seamless workflow between reservoir engineers and production technologists.
This paper presents a combination of conventional and innovative techniques that provide a novel workflow for reservoir engineers and production technologists to quickly evaluate various reservoir development scenarios.
Title: Evaluation of Infill Drilling Opportunities in Lekhwair Field, Oman
Authors:
Shekhar Jayanti, SPE, Anil Chopra, SPE, Ronald M. Giordano, SPE, Hua Yuan, SPE, and Hongguang Tie, SPE, PetroTel Inc. and Ali Suleimani, SPE, Ali Gheithy, SPE, and Clement Edwards, SPE, Petroleum Development Oman
SPE Annual Technical Conference and Exhibition, 11-14 November 2007, Anaheim, California, U.S.A.
Copyright 2007. Society of Petroleum Engineers
Traditional infill drilling evaluations either use empirical techniques based on ad-hoc esimates of drainage areas or reservoir simulation of the field-level benefits of an infill drilling program. The former approach ignores the impact of reservoir heterogeneities while the latter approach makes it difficult to evaluate the contribution that each infill well makes to the field-level benefit. Our approach isolates the impact of each infill well and provides a fast and novel methodology to evaluate the incremental benefit while accounting for reservoir heterogeneity, well conditions, pattern configuration, injection rates, and voidage replacement ratio. This type of analysis helps optimize the number of wells to be drilled and at the same time leads to increased oil recovery through better waterflood management.
Streamline analysis was used to identify dead spots and regions of unswept oil in a part of the field. A novel waterflood management workflow was used to evaluate new infill well configuration strategies to increase oil recovery and better manage the waterflood. Optimization studies were also conducted to minimize the number of wells with the right combination of injectors and producers and obtain significant incremental benefits. Work is underway in the field to implement these recommendations and early results point to the success of this approach.
This paper presents a novel approach for evaluating the impact of infill drilling. The marginal utility of each infill well is calculated and then is used to optimize the number of wells and maximize oil recovery. The approach presented can be used to quantify the impact of infill drilling and increase oil rate and recovery in similar reservoirs.
Title: Application of Neural Networks to Modeling Fluid Contacts in Prudhoe Bay
Authors:
Panda, M. N., Zaucha, D. E., Perez, G., Chopra, A. K., ARCO Exploration and Production Technology
SPE Journal Volume 1, Number 3 September 1996 Pages 303-312
Copyright 1996. Society of Petroleum Engineers
The proposed method uses oil, gas, and water production, perforation history, permeability, sand and shale distribution, and surveillance data at surrounding wells as input to an ANN to predict the fluid distribution at a target well. A two-step method is developed to design an ANN. The first step trains the network using previously measured data as input and output, and thus establishing the internal rules of the network. The second step uses the trained network to estimate the fluid distribution at target wells. Results show that the ANN method can predict fluid distribution at target wells more accurately and consistently than the conventional regression-based methods.
Title: Integrated Geostatistics for Modeling Fluid Contacts and Shales in Prudhoe Bay
Authors:
Godofredo Perez, SPE, A.K. Chopra, SPE, Arco E&P Technology, and C.D. Severson, SPE, Arco Alaska Inc.
SPE Formation Evaluation Volume 12, Number 4 December 1997 Pages 213-220
Copyright 1997. Society of Petroleum Engineers
The proposed methodology integrates the reservoir description and surveillance data within the same geostatistical framework. The methodology transforms surveillance logs and shale data to indicator variables. These variables are then utilized to analyze the vertical and horizontal spatial correlation and cross-correlation of gas and shale at different times and to develop variogram models. Conditional simulation methods are used to generate three-dimensional distributions of gas and shales in the reservoir. Both methods provide a measure of uncertainty in the resulting descriptions. These conditional simulation methods capture the complex three-dimensional distribution of gas-oil contacts through time.
The results of the geostatistical methodology are compared with conventional techniques as well as with the infill wells drilled after the study. The predicted gas-oil contacts and shale distributions are in close agreement with the gas-oil contacts observed at the infill wells.
Title: An Integrated Approach to Estimate Well Interactions
Authors:
Panda, M.N., Chopra, A.K., Arco Exploration and Production Technology
SPE India Oil and Gas Conference and Exhibition, 17-19 February 1998, New Delhi, India
Copyright 1998. Society of Petroleum Engineers Preview
Currently, the injector-producer interaction is estimated by visually cross correlating injection and production rates of different well pairs in a pattern. Regional discontinuities in reservoir properties including faults and pinchouts are inferred from the cross correlation. Such statistics-driven methods are stable as shown previously in many such fields of applications. There are, however, two problems with this approach: firstly, the results obtained using the cross correlation are non-unique and secondly, the process is extremely time consuming.
This paper presents a new integrated approach to determine the injector-producer interaction. First, a multi-variate data set consisting of production, injection, petrophysical, sand/shale, and well location information is generated. An artificial neural network (NN) is then trained to estimate the well interaction between different well pairs. The estimated well interactions are used to determine the presence of heterogeneities, such as faults, pinchouts, regional permeability trends etc. Results show that the new integrated app roach can quantify injector-producer connectivity more accurately, consistently, and inexpensively than the conventional methods. The new method will, thus, facilitate better reservoir management of fields where the knowledge of injector- producer interaction can affect recovery efficiency, sweep, reservoir performance, and infill well placement.
Title: Reservoir Modeling Using Scale Dependent Data
Authors:
M.N. Panda, C. Mosher, A.K. Chopra, ARCO Exploration and Production Technology
SPE Annual Technical Conference and Exhibition, 5-8 October 1997, San Antonio, Texas
Copyright 1997, Society of Petroleum Engineers
Current geostatistical methods map lithofacies, porosity, and permeability on a network of grid nodes called the geologic modeling cells. Pseudo point properties that assimilate information from all available data are modeled onto model cells using one of several available conditional simulation techniques. Some methods attempt to combine data with varying support and data with multiple scale support through simple correlations. For example, one approach to incorporate geophysical data is to use a direct transform of the seismic signal to rock properties through a linear regression or crossplot. Reservoir models built using such linear correlations tend to be case specific with little generality.
This paper presents a method for identifying the impact of multi-scale data (data that measure average property over multiple flow units) on reservoir modeling. It examines the information about the reservoir system each data type carries. For example, what fraction of core scale variability is captured by well log data. We also present a consistent method for integrating multi-scale data. Through a series of numerical simulations, we show the impact of heterogeneity of reservoir properties on the fluid flow performance.
Title: Enhanced Geostatistical Mapping of Reservoir Fluids
Authors:
Perez, G., Chopra, A. K., ARCO Exploration and Production Technology; Severson, C. D., ARCO Alaska Inc.
International Meeting on Petroleum Engineering, 14-17 November 1995, Beijing, China
Copyright 1995, Society of Petroleum Engineers, Inc. Preview
The major sources of data used in the geostatistical methodology are the surveillance and shale databases. The surveillance data provide the locations of fluids (oil, gas and water) intervals at the wells based on logs. The shale data provide the locations of shales intervals at the wells based on cores and logs. The first step in the methodology is to transform the surveillance and shale data into indicators. Then, the methodology uses indicator variograms to evaluate the spatial correlation of the data. The last step generates multiple equi-probable three-dimensional fluid and shale descriptions using a conditional simulation technique that honors the well data and variograms.
The enhancements introduced into the geostatistical methodology account for more information about the data and quantify the quality of the surveillance data.
The stratigraphic coordinates and vertical proportion curves account for variations in the reservoir structure and major trends in the data, respectively. The indicator variables for fluid movement at different times and shales in different zones account for the different correlations. The quality variables account for the degree of confidence engineers assign to the log interpretations. Cross-validation of the enhanced methodology consisted of the estimation of fluid column thicknesses at infill locations and visualization of three-dimensional distributions of oil and gas in a gravity drainage area of Prudhoe Bay. The results of the methodology are in excellent agreement with actual data.
Title: Incorporating Reservoir Heterogeneity With Geostatistics To Investigate Waterflood Recoveries
Authors:
Don S. Wolcott, SPE, Arco Alaska Inc., and Anil K. Chopra, SPE, Arco E&P Technology
SPE Formation Evaluation Volume 8, Number 1 March 1993 Pages 26-32
Copyright 1993. Society of Petroleum Engineers
Title: Integrated Geostatistical Reservoir Description Using Petrophysical, Geological, and Seismic Data for Yacheng 13-1 Gas Field
Authors:
Yang, C. T., Chopra, A. K., Chu, J., ARCO Exploration and Production Technology; Huang, X., Kelkar, M. G., University of Tulsa
SPE Annual Technical Conference and Exhibition, 22-25 October 1995, Dallas, Texas
Copyright 1995, Society of Petroleum Engineers
This modeling technique is applied to the Yacheng 13-1 Gas Field. The results are compared with porosity models generated using well-log data only, as well as with using seismic amplitude and well-log data since a good correlation between seismic amplitude and well log data is also observed after transforming the data into similar scales.
The results demonstrate a protocol for early integration of geological and geophysical data in a gas reservoir. This approach will allow easy revision and refinement of the description with additional data, such as new well data or new interpretation of the existing data.
Title: Enhanced Geostatistical Mapping of Reservoir Fluids
Authors:
Perez, G., Chopra, A. K., ARCO Exploration and Production Technology; Severson, C. D., ARCO Alaska Inc.
International Meeting on Petroleum Engineering, 14-17 November 1995, Beijing, China
Copyright 1995, Society of Petroleum Engineers, Inc. Preview
The major sources of data used in the geostatistical methodology are the surveillance and shale databases. The surveillance data provide the locations of fluids (oil, gas and water) intervals at the wells based on logs. The shale data provide the locations of shales intervals at the wells based on cores and logs. The first step in the methodology is to transform the surveillance and shale data into indicators. Then, the methodology uses indicator variograms to evaluate the spatial correlation of the data. The last step generates multiple equi-probable three-dimensional fluid and shale descriptions using a conditional simulation technique that honors the well data and variograms.
The enhancements introduced into the geostatistical methodology account for more information about the data and quantify the quality of the surveillance data.
The stratigraphic coordinates and vertical proportion curves account for variations in the reservoir structure and major trends in the data, respectively. The indicator variables for fluid movement at different times and shales in different zones account for the different correlations. The quality variables account for the degree of confidence engineers assign to the log interpretations. Cross-validation of the enhanced methodology consisted of the estimation of fluid column thicknesses at infill locations and visualization of three-dimensional distributions of oil and gas in a gravity drainage area of Prudhoe Bay. The results of the methodology are in excellent agreement with actual data.
Reservoir Studies
Title: The Importance of Water Influx in Gas Reservoirs
Authors:
R.G. Agarwal, R. Al-Hussainy, H.J. Ramey, Jr., Texas A&M U.
Journal of Petroleum Technology Volume 17, Number 11 November 1965 Pages 1336-1342
Copyright 1965 Society of Petroleum Engineers
The manner of estimating water-drive gas reservoir recovery can vary considerably. Examples are: the steady-state method, the Hurst modified steady-state method, and various unsteady-state methods such as those of van Everdingen-Hurst, Hurst, and Carter-Tracy. The Carter-Tracy water influx expression was used in this study.
In certain cases, it appears that gas recovery can be increased significantly by controlling the production rate and manner of production. For this reason, the potential importance of water influx in particular gas reservoirs should be investigated early to permit adequate planning to optimize the gas reserves.
Title: Analyzing Well Production Data Using Combined Type Curve and Decline Curve Analysis Concepts
Authors:
Agarwal, Ram G., Gardner, David C., Kleinsteiber, Stanley W., Fussell, Del D., Amoco Exploration and Production Company
SPE Annual Technical Conference and Exhibition, 27-30 September 1998, New Orleans, Louisiana
Copyright 1998, Society of Petroleum Engineers
Decline curve analysis methods, in a variety of forms, have been used in the petroleum industry for more than fifty years to analyze production data and forecast reserves. Type curve analysis methods have become popular, during the last thirty years, to analyze pressure transient test (e.g. buildup, draw-down) data.
Pressure transient data can be costly to obtain and may not be available for many wells, while well production data is routinely collected and is even available from industry data bases. In the absence of pressure transient data, a method that cause readily available well production data to perform pressure transient analysis would be very beneficial. The result is the development of these new production decline type curves.
These new production decline type curves represent an advancement over previous work because a clearer distinction can be made between transient and boundary dominated flow periods. The new curves also contain derivative functions, similar to those used in the pressure transient literature to aid in the matching process. These production decline curves are, to our knowledge, the first to be published in this format specifically for hydraulically fractured wells of both infinite and finite conductivity. Finally, these new curves have been extended to utilize cumulative production data in addition to commonly used rate decline data.
Waterflood Optimization
Title: A Streamline Based Reservoir Management Workflow to Maximize Oil Recovery
Authors:
Ronald M. Giordano, SPE, Shekhar Jayanti, SPE, Anil Chopra, SPE, Hua Yuan, SPE, Kazuhiro Asakawa, SPE, PetroTel Inc. Ali Suleimani, SPE, Ali Gheithy, SPE, and Clement Edwards, Petroleum Development Oman
SPE/EAGE Reservoir Characterization and Simulation Conference, 28-31 October 2007, Abu Dhabi, UAE
Copyright 2007. Society of Petroleum Engineers
This paper presents a robust and proven reservoir management workflow that can be used to evaluate short to medium term development scenarios proposed by production technologists. Traditionally, reservoir engineers make medium to long term field development decisions based on complex reservoir models, while production technologists make short term well level decisions based on operational data. As a result, the reservoir engineers and production technologists frequently work independent of each other. This paper provides the workflow and techniques that enable reservoir engineers and production technologists to work in an integrated manner and thereby increase production and recovery in a mature field.
An integrated reservoir management workflow was developed that can help not only the reservoir engineer to understand the reservoir dynamics, but also the production technologist to evaluate everyday production opportunities. This evaluation is brought about by integrating streamlines from finite-difference simulations, well performance data, and novel performance diagnostic plots. This approach was successful in developing a dynamic model for the Lekhwair field. The proposed workflow and applications provide efficient ways to maximize oil recovery in a seamless workflow between reservoir engineers and production technologists.
This paper presents a combination of conventional and innovative techniques that provide a novel workflow for reservoir engineers and production technologists to quickly evaluate various reservoir development scenarios.
Title: Evaluation of Infill Drilling Opportunities in Lekhwair Field, Oman
Authors:
Shekhar Jayanti, SPE, Anil Chopra, SPE, Ronald M. Giordano, SPE, Hua Yuan, SPE, and Hongguang Tie, SPE, PetroTel Inc. and Ali Suleimani, SPE, Ali Gheithy, SPE, and Clement Edwards, SPE, Petroleum Development Oman
SPE Annual Technical Conference and Exhibition, 11-14 November 2007, Anaheim, California, U.S.A.
Copyright 2007. Society of Petroleum Engineers
Traditional infill drilling evaluations either use empirical techniques based on ad-hoc esimates of drainage areas or reservoir simulation of the field-level benefits of an infill drilling program. The former approach ignores the impact of reservoir heterogeneities while the latter approach makes it difficult to evaluate the contribution that each infill well makes to the field-level benefit. Our approach isolates the impact of each infill well and provides a fast and novel methodology to evaluate the incremental benefit while accounting for reservoir heterogeneity, well conditions, pattern configuration, injection rates, and voidage replacement ratio. This type of analysis helps optimize the number of wells to be drilled and at the same time leads to increased oil recovery through better waterflood management.
Streamline analysis was used to identify dead spots and regions of unswept oil in a part of the field. A novel waterflood management workflow was used to evaluate new infill well configuration strategies to increase oil recovery and better manage the waterflood. Optimization studies were also conducted to minimize the number of wells with the right combination of injectors and producers and obtain significant incremental benefits. Work is underway in the field to implement these recommendations and early results point to the success of this approach.
This paper presents a novel approach for evaluating the impact of infill drilling. The marginal utility of each infill well is calculated and then is used to optimize the number of wells and maximize oil recovery. The approach presented can be used to quantify the impact of infill drilling and increase oil rate and recovery in similar reservoirs.
Title: Incorporating Reservoir Heterogeneity With Geostatistics To Investigate Waterflood Recoveries
Authors:
Don S. Wolcott, SPE, Arco Alaska Inc., and Anil K. Chopra, SPE, Arco E&P Technology
SPE Formation Evaluation Volume 8, Number 1 March 1993 Pages 26-32
Copyright 1993. Society of Petroleum Engineers
Well Testing(PTA)
Title: Analyzing Well Production Data Using Combined-Type-Curve and Decline-Curve Analysis Concepts
Authors:
Ram G. Agarwal, David C. Gardner, Stanley W. Kleinsteiber, Del D. Fussell, Amoco Exploration & Production Co.
Journal SPE Reservoir Evaluation & Engineering Volume 2, Number 5 October 1999 Pages 478-486
Copyright 1999 Society of Petroleum Engineers
These new production decline-type curves represent an advancement over previous work because a clearer distinction can be made between transient- and boundary-dominated flow periods. They also provide a more direct and less ambiguous means of determining reserves. The new curves also contain derivative functions, similar to those used in the pressure transient literature to aid in the matching process. These production decline curves are, to our knowledge, the first to be published in this format specifically for hydraulically fractured wells of both infinite and finite conductivity. Finally, these new curves have been extended to utilize cumulative production data in addition to commonly used rate decline data.
Title: Evaluation and Performance Prediction of Low-Permeability Gas Wells Stimulated by Massive Hydraulic Fracturing
Authors:
Agarwal, R.G., Amoco Production Co.; Carter, R.D., Amoco Production Co.; Pollock, C.B., Amoco Production Co.
Journal of Petroleum Technology Volume 31, Number 3 March 1979 Pages 362-372
Copyright 1979 Society of Petroleum Engineers
Title: Combined Analysis of Postfracturing Performance and Pressure Buildup Data for Evaluating an MHF Gas Well
Authors:
Bostic, James N., Amoco Production Co.; Agarwal, Ram G., Amoco Production Co.; Carter, Robert D., Amoco Production Co.
Journal of Petroleum Technology Volume 32, Number 10 October 1980 Pages 1711-1719
Copyright 1980 Society of Petroleum Engineers
Title: Annulus Unloading Rates as Influenced by Wellbore Storage and Skin Effect
Authors:
RAMEY JR., HENRY J., STANFORD U.; AGARWAL, RAM G., AMOCO PRODUCTION CO.
SPE Journal Volume 12, Number 5 October 1972 Pages 453-462
Copyright 1972 Society of Petroleum Engineers
Title: An Investigation of Wellbore Storage and Skin Effect in Unsteady Liquid Flow: I. Analytical Treatment
Authors:
Agarwal, Ram G., Pan American Petroleum Corp.; Al-Hussainy, Rafi, Mobil Research and Development Corp.; Ramey Jr., H.J., Stanford U.
SPE Journal Volume 10, Number 3 September 1970 Pages 279-290
Copyright1970 Society of Petroleum Engineers
Title: Pressure Transient Behavior of Slanted Wells in Single- and Multiple-Layered Systems
Authors:
Khatteb, H.A., Yeh, N-S., Agarwal, R.G., Amoco Production Co.
SPE Annual Technical Conference and Exhibition, 6-9 October 1991, Dallas, Texas
Copyright 1991, Society of Petroleum Engineers
The purpose of this paper is to present pressure transient responses for a variety of cues using the finite element and the analytical solutions. The slanted wellbore cues include the effect of partial penetration, wellbore storage, and reservoir heterogeneity for single layered systems, and typical pressure transient responses for multiple layered systems. The important parameters which influence the pressure behavior of slated well sin a layered reservoir, with and without interlayer crossflow, will be presented. In addition, the response of a slanted well in a naturally fractured (dual porosity) system will be discussed. Finally, the pressure transient analysis of the data using field examples will be shown to demonstrate the usage of the developed model.
The present study of the pressure transient responses of slanted wells in both single and multiple layered systems should enhance our understanding and add to our capability to design and analyze well tests.
Title: Pressure Transient Analysis of Injection Wells in Reservoirs With Multiple Fluid Banks
Authors:
Yeh, N-S., Agarwal, R.G., Amoco Production Co.
SPE Annual Technical Conference and Exhibition, 8-11 October 1989, San Antonio, Texas
Copyright 1989, Society of Petroleum Engineers
Title: Development and Application of New Type Curves for Pressure Transient Analysis
Authors:
Yeh, N-S., Agarwal, R.G., Amoco Production Co.
International Meeting on Petroleum Engineering, 1-4 November 1988, Tianjin, China
Copyright 1988, Society of Petroleum Engineers
New type curves are presented for wells in radial systems with wellbore storage and skin, and vertically fractured wells with uniform-flux, infinite-conductivity and finite-conductivity fractures. Field examples are included to illustrate the utility of the new type curves and the analysis procedure. The possible application of this method to heterogeneous systems such as naturally reservoirs are also discussed.
Title: Systematic Design and Analysis of Step-Rate Tests To Determine Formation Parting Pressure
Authors:
Singh, P.K., Agarwal, R.G., Krase, L.D., Amoco Production Co.
SPE Annual Technical Conference and Exhibition, 27-30 September 1987, Dallas, Texas
Copyright 1987, Society of Petroleum Engineers
A systematic investigation of several significant factors affecting SRT design and analysis is presented. The analysis of SRT data influenced by wellbore storage and changing wellbore storage is investigated. The proper application of multirate analysis methods to SRT data is outlined. A new method is proposed for determining parting pressure from SRT data on fractured wells. Field examples are included. This work should significantly enhance our ability to successfully design and analyze the step rate tests.
Title: A NEW METHOD TO ACCOUNT FOR PRODUCING TIME EFFECTS WHEN DRAWDOWN TYPE CURVES ARE USED TO ANALYZE PRESSURE BUILDUP AND OTHER TEST DATA
Authors:
Agarwal, Ram G., Amoco Production Co.
SPE Annual Technical Conference and Exhibition, 21-24 September 1980, Dallas, Texas
Copyright 1980, American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.
In view of the preceding, a novel but simple method has been developed which eliminates the dependence on producing time effects and allows the user to utilize the existing drawdown type curves for analyzing pressure buildup data. This method may also be used to analyze two-rate, multiple-rate and other kinds of tests by type curve methods as well as the conventional methods. The method appears to work for both unfractured and fractured wells. Wellbore effects such as storage and/or damage may be taken into account except in certain cases.
The purpose of this paper is to present the new method and demonstrate its utility and application by means of example problems.
Title: REAL GAS PSEUDO-TIME" - A NEW FUNCTION FOR PRESSURE BUILDUP ANALYSIS OF MHF GAS WELLS
Authors:
Agarwal, Ram G., Amoco Production Co.
SPE Annual Technical Conference and Exhibition, 23-26 September 1979, Las Vegas, Nevada
Copyright 1979, American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.
In this paper the real gas pseudo-time is described and its application is demonstrated by means of example problems. Although the discussion in this paper is limited to pressure buildup analysis of vertically fractured gas wells, the utility of this function is not meant to be restricted to such wells only.
Title: Modeling Nonlinear Interactions among Near-Well Flow Restrictions in Well Deliverability Prediction and Simulation
Authors:
M. K. Hwang, SPE, Mobil E & P Technical Center
SPE Reservoir Simulation Symposium, 14-17 February 1999, Houston, Texas
Copyright 1999. Society of Petroleum Engineers
Title: Reservoir Descriptions Via Pulse Testing: A Technology Evaluation
Authors:
Chopra, A.K., Amoco Production Co.
International Meeting on Petroleum Engineering, 1-4 November 1988, Tianjin, China
Copyright 1988, Society of Petroleum Engineers
The integrated approach is applied to a pulse test pilot completed in a San Andres reservoir. The usefulness of pulse testing is found to be highly reservoir specific. Pulse test data alone are not sufficient to derive reservoir descriptions for multilayer heterogeneous reservoirs and must be used in conjunction with geological, petrophysical, and single well pressure transient data. Pulse testing may not provide an adequate definition of vertical layer heterogeneities for tertiary miscible gas performance predictions and can be used only to refine the definition of high speed layers which control gas cycling in a tertiary miscible gas process. The pulse test derived reservoir description may be adequate for waterflooding predictions under certain situations. For primary depletion predictions, single well pressure transient data are sufficient when coupled with geological and petrophysical data. The integrated approach to evaluate pulse testing is recommended before actually conducting pulse tests in the field.
Title: Estimation of Condensate Dropout Effects on Well Productivity as Skin Change with Multiplicative Interactions Among Skin Components
Authors:
Hwang, M.K., Odeh, A.S., Mobil R & D Corp. SPE 29894-MS 1995
Middle East Oil Show, 11-14 March 1995, Bahrain
Copyright 1995, Society of Petroleum Engineers
The new equation developed here has significant implications in various engineering analyses. The conventional method can grossly overestimate well deliverability, if the total skin value is computed from individual components. Conversely, when an individual component (such as Sm) is back-calculated from the total skin obtained from pressure transient analysis, the conventional method can grossly overestimate Sm. Also, this new equation can be used to predict simulation impacts of different wellbore description and of adjustments made in permeability distributions and skin components during history matching.
