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The Hunt for Hydrocarbons
SwRI scientists integrate geology, geophysics, and seismic and production data to create detailed models of oil and gas reservoirs
by Jorge O. Parra, Ph.D.
Hydrocarbon exploration and recovery rely on sophisticated means of subsurface geological characterization. Since drilling for oil and gas began in earnest during the early years of this century, many exploration techniques have been used, from identifying surface features that might overlie oil traps such as anticlinal folds, to drilling exploratory wells in promising areas, to conducting increasingly sophisticated seismic surveys.
As one of the world's most prolific oil producers in recent decades, but with relatively modest petroleum resources, the U.S. has quickly depleted its most accessible reserves. Even so, it is estimated that up to 75 percent of the potentially recoverable oil in this country remains underground. About 25 to 30 percent can be extracted through enhanced recovery operations (EOR), in which natural gas, water, steam, and/or chemicals are injected into a reservoir to reduce oil viscosity and force the oil toward a pumping well. EOR is commonly used, but it is a costly technique that does not address the elusive remaining half of the nation's oil.
New approaches are needed to accurately map the structures that still harbor hydrocarbons, particularly highly fractured or discontinuous fields where substantial pockets of oil may exist that do not share the same production flow path. Determining the nature and extent of reservoir discontinuities also has a financial impact on recovery operations, however. Increasingly comprehensive and detailed subsurface information will help reservoir engineers make better decisions concerning production economics.
The heterogeneous nature of hydrocarbon reservoirs is the main reason for productivity variations and low rates of resource recovery. Typical reservoir heterogeneities include shale barriers in sands; faults and fractures; and variabilities in porosity, permeability, and fluid saturation. The geometry, orientation, distribution, and physical properties of these heterogeneities must be understood to determine where hydrocarbons are stored and how they flow to a producing wellbore.
Ideally, a complete image of the reservoir at all scales is needed, from large-scale structural and stratigraphic variations to small-scale changes in porosity, facies distributions, and rock textures. Information about the density and degree of heterogeneity at all scales throughout the three-dimensional reservoir can be related to stratigraphic variations through geological modeling.
Southwest Research Institute scientists have made significant contributions to hydrocarbon reservoir characterization in the past several years by developing theoretical and numerical models that integrate core, well log, surface, and interwell (borehole-to-borehole) seismic data, as well as vertical seismic profiling (VSP) and reverse VSP data, from producing oil fields. VSP generates data by positioning a seismic source on the surface and detectors in a borehole, and reverse VSP records data from a source positioned in a borehole and detectors planted near the surface. When integrated with production data from the field to delineate structural features in reservoirs and to predict permeability distribution, modeling can take much of the guesswork and expense out of locating and mapping petroleum production paths.
Support for such endeavors is provided by organizations such as the U.S. Department of Energy (DOE), which seeks to expand the knowledge base through which industry can introduce additional energy resources to the market in an environmentally acceptable, cost-effective manner, and the Gas Research Institute (GRI), which is dedicated to research and development in support of the gas industry.
In one of the first SwRI projects related to advanced methods of reservoir characterization for the DOE, scientists constructed models to evaluate the accuracy of interwell seismic and high-resolution reverse VSP measurements at the Buckhorn test site near Quincy, Illinois, from 1990 to 1992. This oil field, owned by Western Kentucky Petroleum, lies in the Silurian Kankakee limestone formation.
SwRI researchers used reverse VSP to map the formation, a prolific producer less than 8 meters (m) thick and horizontally distributed at a depth of about 200 m. Well log and core information provided by Western Kentucky Petroleum suggested significant lateral changes in porosity within the Kankakee. The interwell seismic method was applied to determine other rock physical properties between wells, such as pore fluid viscosity and permeability of porous zones. Experimental results demonstrated that the fractured rock matrix and wide porosity distribution caused high attenuation (decreased wave amplitude) in the seismic pulses traveling through the formation, verifying model predictions.
As the successful modeling and analysis effort was under way in Illinois, GRI and DOE initiated a field trial of an SwRI geophysical model of the Gypsy test site in Oklahoma. The Gypsy test site rests in a fluvial sandstone, or ancient riverbed, that includes an underground aquifer. British Petroleum owns the site, which is used for evaluations of subsurface characterization techniques that can be applied to oil fields.
The goal of this project was to investigate the suitability of interwell seismic logging techniques for interpreting oil and gas reservoir geology and rock physical properties. The work involved a balanced study of theoretical and numerical modeling of seismic waves transmitted between pairs of wells, combined with experimental data acquisition and processing under controlled field conditions. The field applications were aimed at correlating high-resolution seismic measurements with a detailed interpretation of heterogeneous hydrocarbon-bearing formations.
Constructed from well logs, interwell seismic data, and core information, the model incorporates an SwRI-developed relation between compressional wave attenuation and dispersion (velocity change in the wave that accompanies attenuation) and permeability anisotropy. Anisotropy refers to a property's tendency to have different values when measured along different directional axes.
Evaluation results demonstrated the model's ability to predict the dispersion of seismic waves traveling in the sandstone reservoir, as well as how dispersion relates to permeability anisotropy. This work led to the development of algorithms to extract permeability anisotropy data from attenuation and dispersion data to map fluid flow distribution in a reservoir. In addition, the work at Gypsy demonstrated the suitability of mapping guided waves to determine reservoir continuity.
Guided waves occur when a low seismic velocity rock layer, such as sandstone, is bounded by higher velocity layers. Compressional (P) and shear (S) waves originating in the low-velocity layer remain in that layer, confined by the higher velocity layers. Because hydrocarbons are generally found in porous, permeable rocks sandwiched between impermeable rock layers, guided waves can provide important information about the geophysical properties of a reservoir.
The SwRI-developed model predicted not only the presence of guided waves, but their modal components as well. Normal modes indicate P- and S-wave velocities that are higher in both bounding layers than in the confined layer, a condition present in a continuous reservoir. Leaky modes occur when S-wave velocities are slower in the bounding layer than P-wave velocities are in the confined layer, representing an energy loss. At Gypsy, the model showed that both leaky and normal modes can be trapped in low-velocity layers, and that their presence in high-resolution interwell seismic data can be used to delineate reservoir boundaries.
To transfer the findings of the Gypsy project to the gas industry, GRI asked SwRI to study the Stratton gas field in the South Texas Frio Formation, beginning in 1993. The Stratton Field is owned by Union Pacific Resources Company (UPRC), which contributed well log and seismic data for the study. SwRI researchers incorporated petrophysical properties and the interval geologies of the upper and middle Frio Formation in computer models that assessed the feasibility of detecting guided waves between wells more than half a mile apart.
The model results predicted that guided seismic waves could be transmitted and detected in the upper Frio formation and that energy in the form of leaky and normal modes would be trapped in the low-velocity shale waveguides in the formation. The project has been extended through 1998 to conduct continuity logging experiments to confirm the model predictions.
In 1996, SwRI was contracted to characterize a highly fractured reservoir in collaboration with Texas A&M University. During this ongoing project, theoretical and numerical model studies will be linked with a balanced petrophysical and engineering program for the development of advanced concepts of borehole and seismic measurement techniques. The DOE-affiliated National Institute for Petroleum and Energy Research is sponsoring the project, which is being conducted at the Twin Creek formation in the Utah-Wyoming Overthrust Belt.
In low-porosity, low-permeability formations, natural fractures are the primary source of permeability, controlling both production and injection of fluids. Open fractures do not contribute significantly to total porosity, but they provide an increased drainage network. An important aspect of characterizing reservoir fracture orientation and permeability is determining how fractures affect the propagation of acoustic and seismic waves through the rock.
The goals of the Twin Creek project are to map the orientation and extent of fracture zones and to predict permeability distribution using multiphase (oil and gas or oil and water) production data. The Institute is providing petrophysical and geological data, well log data interpretation, and seismic modeling, and A&M is contributing expertise in petroleum engineering.
Well logs and borehole cuttings have been analyzed to ascertain the geologic factors controlling horizontal and vertical rock density as well as the distribution of fractures in the formation and the extent to which porosity contributes to hydrocarbon production in the field. These results have been integrated with seismic data to determine if the fractured intervals have a characteristic seismic signature. So far, the analyses have confirmed the lithology indicated by the cuttings - the main fracture intervals are bounded by shales and are more dolomitic than the rest of the formation.
At the conclusion of a future phase of the project in 1998, all of the model predictions will be integrated with the hydrocarbon production history of the field to provide a comprehensive overview of fracture and permeability distribution.
These representative projects illustrate the necessity of selecting the most appropriate measurement techniques and developing tailored models for each type of field under investigation. Despite these considerations, modeling is less expensive and provides more comprehensive data than a test well, which can cost several million dollars. The modeling and analysis approach is gaining increased acceptance in the industry as an important aspect of reservoir characterization. However, each stage of model development must have experimental verification to ensure industry acceptance. Through the projects described here, SwRI has demonstrated the accuracy and usefulness of a number of reservoir characterization models.
The work described here was made possible by the contributions of several individuals. Among them are Dr. Thomas E. Owen (University of Texas at San Antonio), Dr. Brian J. Zook and Dr. Bob M. Duff (Southwest Research Institute), Dr. Akhil Datta-Gupta (Texas A&M University), Dr. Raymon L. Brown (Oklahoma Geological Survey), Mr. James Peters, (Union Pacific Resources Company), Dr. Richard Parker (Gas Research Institute), Dr. Anthony Gorody (Universal Geoscience Consulting), Dr. Hughbert A. Collier (Tarleton State University), and Dr. P.-C. Xu, University of Toronto.
Published in the Fall 1997 issue of Technology Today®, published by Southwest Research Institute. For more information, contact Joe Fohn.