RESERVOIR CHARACTERIZATION TECHNOLOGIES FOR THE NEXT MILLENIUM

Based upon a workshop co-sponsored by PTTC's Texas Region and The Bureau of Economic Geology on February 1, 2000, in Midland, Texas

BOTTOM LINE

Advanced technologies including computer visualization, multi-component seismic, fracture modeling, and borehole imaging are being developed by the Bureau of Economic Geology, The University of Texas at Austin. Opportunities exist for operators to participate with the Bureau in characterization and reservoir exploitation studies to increase oil and gas recovery on State and University Lands.

PROBLEM ADDRESSED

Advanced technologies with great promise for reservoir characterization studies are being developed at the Bureau of Economic Geology, The University of Texas at Austin. Advanced visualization, especially virtual imaging, has already begun to redefine approaches to characterization and field management. A new multi-component seismic technique, currently being developed, will provide better understanding of stratigraphic relationships, lithological distributions, and pore-fluid properties. Quartz-filled microfractures in clastic sediments from fractured reservoirs are being utilized to quantify the size distributions of much less abundant macrofractures that can control fluid flow. This technique is proving to be a cost-effective way to construct a dualporosity simulation for large regions in the subsurface. Borehole imaging logs, when properly calibrated with core, can resolve facies successions and some karst features with degrees of accuracy that can rival core description.

KEY WORDS:

Borehole Imaging Logs, Fracture Modeling, Microfracture Analysis, Multi-component Seismic, Reservoir Characterization, Virtual Imaging, 9C3D Seismic Data

SPEAKERS

Overview and Multi-component Seismic in Reservoir Characterization
Bob Hardage, Bureau of Economic Geology

Virtual Visualization Technologies for Reservoir Characterization
Scott Rodgers, Bureau of Economic Geology

Innovative Fracture Characterization and Modeling
Steve Laubach, Bureau of Economic Geology

University Lands Research in West Texas; Borehole Imaging Logs in Carbonate Reservoirs
Steve Ruppel, Bureau of Economic Geology

The Geologist's Role in Reservoir Characterization
Scott W. Tinker, Bureau of Economic Geology

TECHNOLOGY OVERVIEW

New technologies and new applications for current technologies are being developed by the Bureau of Economic Geology (BEG), The University of Texas at Austin, for collecting, visualizing, and analyzing data critical to reservoir characterization. These include advanced visualization, multi-component seismic, fracture modeling, and borehole imaging technologies.

Advanced Visualization Technologies for Reservoir Characterization and Field Management. There has never been a greater need for methods to convey information effectively across discipline boundaries. Application of advanced computational and visualization technologies is a significant step forward in this process. Advanced computer technologies offer degrees of scale, accuracy, and complexity that could only be imagined a decade ago. Integration of these parameters in the hydrocarbon discovery process underscores the need for development of contextual frameworks with which to make sense of the vast array of information now at our disposal. Application of advanced visualization technologies, especially virtual imaging, marks a significant change in approach to hydrocarbon recovery and field management strategies.

Multi-component Seismic Technology in Reservoir Characterization. Regardless of the type of seismic source, the seismic wavefield that propagates through rock layers is composed of a compressional (P) wave component and two shear (SV and SH) wave components. A principal difference among these wavefields is the manner in which they cause rock particles to oscillate. Creation of optimal images of subsurface targets will occur if a seismic wavefield is segregated into its component P, SV, and SH parts so that a P-wave image can be made that has minimal contamination from interfering SV and SH modes. Similarly, an SV image must have no P and SH mode contamination, and an SH image must lack P and SV contamination.

In consolidated rocks the P wave travels at a velocity that is approximately two times faster than either the SH or SV wave. This velocity difference aids in separating interfering modes. However, a more powerful technique for separating a seismic wavefield into its component parts is to concentrate on the distinctions in the particle displacement associated with P, SH, and SV modes.

P, SH, and SV particle displacements form an orthogonal coordinate system (Figure 1). The fundamental requirement for multi-component seismic imaging is that reflection wavefields must be recorded with orthogonal 3-component sensors that allow the P, SH, and SV particle motions to be recognized. At present almost all seismic data are recorded with single-component sensors that do not allow SH and SV wave modes to be utilized.

In onshore seismic work, multi-component seismic imaging can be further aided by using three special-purpose sources (Figure 2) that successively generate three distinct illuminating wavefields. The first source applies a vertical impulse to the earth; the second source applies a horizontal impulse in a chosen direction; and the third source applies a horizontal impulse that is orthogonal to that applied by the second source. The vertical source produces a wavefield that has a strong P-wave component; the horizontal sources produce wavefields with strong, polarized S-wave components. When each of these three wavefields is recorded in a time-sequence succession by 3-component sensors (instead of the "normal" single-component geophone), the result is 9component seismic data. When the reflected wavefields are recorded by a 3-D grid of 3component sensors, the data are referred to as 9C3D.

But why is there interest in multi-component imaging? Each particle displacement vector (P, SH, and SV) reacts to rock properties in a different way and thus provides different information about rock systems and subsurface targets. To date, almost all seis mic images of the subsurface have been only P-wave images. By developing technology that allows P, SH, and SV images to be constructed, much more information about subsurface geology, stratigraphic relationships, lithological distributions, and pore-fluid properties becomes available.

The Exploration Geophysics Laboratory (EGL) was created at The University of Texas at Austin to develop new seismic exploration technologies that can improve the understanding and management of earth systems, primarily hydrocarbon reservoirs. The primary research objective at EGL is to expand conventional single-component 3-D seismic imaging technology into 3-D multi-component seismic imaging of subsurface targets. EGL scientists are convinced that this new multi-component seismic information will be essential for better understanding of earth processes and reservoir management.

Fracture Modeling
Ongoing research is aimed at enhancing exploration and production in fractured reservoirs. Macroscopic fractures in reservoirs provide the largest impact on fluid flow; however, they are orders of magnitude less abundant than microscopic fractures. Data about macrofractures is also difficult to obtain with conventional techniques. Microfractures, in contrast, are so abundant that they can be well studied in small samples. Fracture research at the BEG is examining the hypothesis that micro-and macrofractures can be used to predict critical fluid flow characteristics of associated macrofractures.

Quartz-filled microfractures in clastic sediments from fractured reservoirs are readily observed when their images are generated using cathodoluminescence with the scanning electron microscope. Such microfracture imaging permits determination of microfracture orientations, relative timing or origin, and size distribution. Using this method, orientation and timing of microfractures commonly compare favorably with those associated with conductive macrofractures.

Microfractures are sufficiently abundant in the formations studied at the Bureau that the size distributions can be quantified. In special cases, when fracture size (mechanical apertures and/or lengths) of both micro-and macrofractures can be measured in the same rocks, it has been found that the spatial frequency of fractures, as a function of fracture size, follows power-law distributions over at least 4 to 5 orders of magnitude. This confirms that microfractures can be used to quantitatively predict the spatial frequency of associated macrofractures.

On the basis of these techniques and observations, the BEG is developing an approach to fracture modeling that is both cost effective and grounded on local fracture observation. Microfracture observations collected on a bed-by-bed basis are used to make statistical predictions of key macrofracture attributes. From these predictions, multiple discrete fracture models are generated for each bed, representing volumes comparable to those of cells in dual-porosity simulations. These results can then be used to construct a dual-porosity simulation for large regions in the subsurface.

Borehole Imaging Logs in Carbonate Reservoirs
Resolution of complex facies and fabric variations in carbonate reservoirs is fundamental to accurate definition of petrophysical properties and construction of efficient reservoir models. Normally, adequate characterization of carbonate reservoir rock requires large numbers of cores. However, some modern wireline logs, when properly calibrated with cores, can provide robust resolution of carbonate reservoir attributes that can rival that obtained from cores.

Although generally considered to be a tool for fracture identification, calibrated borehole imaging logs can resolve facies successions and cycle boundaries with nearly the same accuracy as cores. In typical Leonardian and Guadalupian platform carbonate successions, tidalflat rocks are readily characterized by a thinly layered pattern, deeper subtidal fusulinid-bearing rocks by a vermiform character, and shallow subtidal rocks by a granular pattern on image logs. Grikes, solution pits, and collapse breccias, commonly associated with karst horizons in Wolfcampian and Pennsylvanian rocks, are also readi ly definable. The detailed resolution of facies, sedimentary structures, cyclicity, and in some cases, pore types provided by properly calibrated borehole image logs compares with that afforded by cores. These logs thus offer a viable, commonly lower cost, alternative for gathering critical rock data for carbonate reservoir characterization.

University and State Lands Field Studies Available
The BEG is conducting characterization and exploitation studies of University and State Lands reservoirs and is seeking active operators of these leases who are interested in working with the Bureau to develop and apply new techniques to increase oil and gas recovery. The goals of the program are to identify remaining hydrocarbon resources, design more efficient techniques for their recovery, and bring about incremental production using state-of-the-art technologies.

All Operators of University Lands leases are eligible to participate with the Bureau. Selection is dependent on approval by The University of Texas System on the basis of potential economic value and operator commitment to implementing results of the studies through drilling and recompletions. Please contact Steve Ruppel at 512-4712965 or stephen. ruppel@ beg. utexas. edu. Operators of State Lands leases are also eligible to participate and should contact Bob Hardage at 512-471-0366 or bob. hardage@ beg. utexas. edu for more information.

CONNECTIONS:

Bureau of Economic Geology,
The University of Texas at Austin,
University Station, Box X,
Austin, Texas 78713-8924
Fax 512-471-0140

Dr. Bob A. Hardage
Phone 512-471-0366,
E-mail bob. hardage@beg.utexas.edu

Dr. Stephen C. Ruppel
Phone 512-471-2965,
E-mail: stephen. ruppel@beg.utexas.edu

Dr. Stephen E. Laubach
Phone 512-471-6303,
E-mail: steve. laubach@beg.utexas.edu

Scott Rodgers
Phone 512-471-2949,
E-mail: scott. rodgers@beg.utexas.edu

For information on PTTC’s Texas region and its activities contact:
Scott Tinker, Bureau of Economic Geology, University of Texas at Austin,
University Station, Box X, Austin, TX 78713-2924
512-471-0209, fax 512-471-0140, E-mail Scott. Tinker@beg.utexas.edu

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The not-for-profit Petroleum Technology Transfer Council is funded primarily by the US Department of Energy’s Office of Fossil Energy, with additional funding from universities, state geological surveys, several state governments, and industry donations.

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