The University of Texas at Austin The Bureau of Economic Geology The University of Texas at Austin Jackson School of Geosciences


Please see the 2011 project overview in this pdf.

Understanding and successfully predicting, characterizing, and simulating reservoir-scale structures are the aims of the Fracture Research and Application Consortium. A key aspect of the program investigates mechanical and chemical processes and interactions over a range of scales. The goal is improved prediction of subseismic scale heterogeneities that influence fluid flow.

Fractures and faults have worldwide importance because of their influence on successful extraction of resources. Many faults and fractures are difficult or impossible to characterize adequately using currently available technology. Consequently, reservoirs that contain fractures have been intractable to describe and interpret effectively, posing serious challenges for exploration, development, and accurate reservoir simulation and reservoir management. More accurate prediction and characterization of fractures holds great potential for improving production by increasing the success and efficiency of exploration and recovery processes.

Scope of the Project

The scope of this project includes measurement, interpretation, prediction, and simulation of fractures. The project

  • creates and tests new methods of measuring attributes of reservoir-scale fractures, particularly as fluid conduits and barriers;
  • extrapolates structural attributes to the reservoir scale through rigorous mathematical techniques and help build accurate and useful 3-D models for the interwell region and develops procedures to do so;
  • develops the capability to accurately predict reservoir-scale deformation using geomechanical, structural, diagenetic, and linked geomechanical/diagenetic models;
  • improves the usefulness of seismic response as an indicator of reservoir-scale structure by developing seismic methods and providing methods of calibrating and verifying seismic fracture detection methods; and
  • designs new ways to incorporate geological and geophysical information into reservoir simulation and verify the accuracy of the simulation.

The aims of this study are both fundamental and practical—to improve prediction and diagnosis of natural-fracture attributes in hydrocarbon reservoirs and accurately simulate their influence on production. New analytical methods will lead to more realistic characterization of fractured and faulted reservoir rocks. These methods will produce data that can enhance well-test and seismic interpretations and that can readily be used in reservoir simulators.

Testing diagnostic and predictive approaches is an integral part of the research. Our requirement is that new methods must ultimately be cost effective. Testing of diagnostic and predictive approaches developed from outcrop, core, and well-test studies is generally carried out in areas of interest to member companies.

Our results are applicable to many types of fractured rocks. Ongoing studies include work on shales, sandstones, and carbonate rocks in both the subsurface and in outcrop.

Research Staff

Our research team comprises staff of the Bureau of Economic Geology, and the Departments of Petroleum & Geosystems Engineering and Geological Sciences, The University of Texas at Austin. This group of petroleum engineers, geophysicists, and geologists applies a wide range of techniques, including geomechanical modeling, rock property testing, quantitative structural geology, microstructural and structural diagenetic analysis, fluid-flow simulation, and geophysical modeling.

Dr. Steve Laubach, Structure and diagenesis

Dr. Jon Olson, Petroleum engineering, geomechanical modeling

Dr. Randy Marrett, Quantitative analysis, structural geology

Dr. Julia Gale, Structural geology

Dr. Peter Eichhubl, Structural diagenesis, brittle deformation and diagenesis

Dr. Jon Holder, Rock property testing, rock physics

Dr. Andras Fall, Fluid inclusions

Dr. Sergey Fomel, Geophysics

Dr. Rob Reed, Microstructural imaging, structural geology

Mr. John Hooker, Microfracture interpretation, structural geology

We have collaborative research arrangements with Drs. Rob Lander and Linda Bonnell, Geocosm and The University of Texas, to study quantitative diagenetic modeling of fracture development. For geophysical aspects of the research we are cooperating with Dr. Sergey Fomel. We are also proud of our graduate student staff, which has included several award-winning students, many of whom are now working in industry.

Many staff members have industry experience or have worked closely with industry and are well aware of the challenges and questions facing exploration and development geoscientists and engineers. Our approach may seem fine-grained and concerned with fundamental issues, but practical applications are central to our goals.

Current and Planned Research: Subsurface Fractures

Each year we combine industry input with our own ongoing research plans to develop a set of key geological and engineering research topics. The research outline and time table will be discussed at the 2009 Research Meeting. We plan to continue research in several areas and effort on trap-scale structural analysis.


Ongoing Research

Surrogate Methods. This research aims to provide methods to acquire site-specific fracture information at user-specified levels of completeness and to yield results even without measuring elusive, difficult-to-sample large fractures (Laubach, 1997; Marrett and others, 1999; Gale, 2002; Laubach, 2003).

We continue to investigate surrogate methods to obtain accurate, site-specific information on fracture intensity, spatial distribution, and fracture porosity preservation. Our automated SEM-based system for collection of microstructural data has allowed us to collect large, statistically meaningful datasets to test and improve these methods (Hooker et al. manuscript, Aperture-size scaling variations in a low-strain fracture set, Cozzette Sandstone, Colorado). These datasets are also used as a key tool for calibrating seismic fracture characterization methods. We are seeking funding leveraged by FRAC support to further our efforts in seismic fracture detection methodologies.The greater volume of data afforded by an automated system has allowed us to apply new insights into fracture spatial scaling (Marrett et al., manuscripts. Fractal and harmonic spatial arrangement of natural fractures). The goals of this part of the FRAC program can be summarized as follows:

  • Testing quantitative scaling and fracture quality information for exploration mapping and horizontal well placement, orientation, and length.
  • Calibrating seismic response to extract more information on fracture attributes.
  • Constraining and validating fracture mechanics-based predictive models.
  • Improving fractured reservoir simulation.

Fundamental studies of fracture formation and closure help put fracture observations in a rigorous theoretical framework. This study is aimed at matching the wealth of new empirical evidence on fracture attributes with fundamental understanding of the processes that produce these fracture patterns. This will help extrapolation of observations to unsampled areas and prediction of fracture attributes.

2The aim is to derive predictions of fracture attributes from pre-drill data such as basin models, diagenetic history modeling, and predictions of rock types based on stratigraphic interpretations. Studies are needed that combine diagenetic and mechanical modeling with rigorous structural and geochemical descriptions of fracture networks. Carefully designed rock-property tests are required and are being carried out in our laboratory to link key parameters in mechanical models (for example, subcritical crack index) with diagenetic parameters that evolve in a systematic way during burial (for example, quartz cement volume and pore pressure; dolomitization; hydrocarbon maturation).

A key aspect of these studies is creation of predictive structural models that can be tested with the types of observations readily available to industry. These studies explicitly take account of fracture-size scaling.

3Predictive Methods. Direct characterization of natural fracture network attributes such as length, spacing, aperture, orientation and intensity in most reservoirs is difficult. The problem stems mostly from the low probability of intersecting vertical fractures with vertical wellbores. Even if fractures do intersect the wellbore they are rarely abundant enough to give a good representation of fracture geometry.

One promising alternative is prediction of fracture geometry from geomechanical modeling based on core derived, fracture mechanics parameters. This process-oriented approach can provide a theoretical basis for deciding what types of fracture attribute distributions are physically reasonable, and how attributes such as length, spacing and aperture are inter-related. The objective of the study is to improve geomechanical fracture network modeling by examining the micro-mechanics of the fracturing process (focused on subcritical crack growth) and by quantifying diagenetic controls on
fracture growth parameters.

The importance of subcritical crack growth is that it exerts fundamental control on fracture pattern geometry. For a given strain event subcritical index (and subcritical index evolution) for a particular bed will control the amount of clustering of the fracture spacing as well as the ultimate fracture intensity.

4Thus, knowing key mechanical parameters can be used to help accurately predict the spatial organization of a fracture pattern. This spatial organization has a primary impact on fluid flow.

We are addressing this issue in three ways:

  • Experimentally, quantifying the subcritical index parameters for various rock types;
  • Numerically, studying how fracture pattern geometry varies with different fracture parameters for different beds;
  • Observationally, trying to constrain our modeling results with field and core data on fractures and the rocks that contain them.

Ultimately, we think that understanding subcritical crack processes and perfecting measurement techniques will enable us to predict which beds in a particular sequence of stratigraphy are most likely to be fractured, and how those fractures are organized throughout the reservoir.

Model results are being compared to our geostatistical work on fracture organization. Rocks currently being tested and modeled include sandstones, carbonates, and shales from a range of geographic and geologic settings. FRAC is compiling subcritical crack index measurements and linking results to rock microstructure observations, and diagenesis predictions. The aim is to predict SCC attributes that existed in the past for use in geomechanical modeling of fracture growth.

Both of the foregoing research areas involve case studies in a wide range of formations worldwide.

5Trap-Scale Initiative. The phase of the project is a multidisciplinary research effort in analysis of fracture patterns at the trap scale. The study will use outcrop and subsurface data from both siliciclastic and carbonate systems. Among the issues to be addressed: 

  • Fracture intensity patterns on and off structure.
  • Fracture style, intensity, and porosity preservation variation with structural position and burial history.
  • Fracture intensity and fracture spatial arrangements at scales ranging from thin section to trap scale.

Fracture intensity and fracture patterns will be studied in the context of high resolution data on fold geometry on outcrop analogs and horizontal core data. The aim is to use this data to guide studies of fracture seismic response.

Leveraged Research

The Fracture Research and Application Consortium leverages industry support through grants from Federal and State funding sources. Currently, the U.S. Department of Energy supports our efforts on understanding the evolution of fracture systems. These studies will continue during  2009. Our research is also supported by a major initiative grant from the Geology Foundation, John A. and Katherine G. Jackson School of Geosciences.

Unconventionals Focused Case Studies

A suite of case studies is being conducted to test FRAC methods in tight gas sandstones and shale reservoirs, in collaboration with FRAC member companies. Call us for further information.   

Fractures in shale-gas reservoirs

Recent activity in shale-gas reservoirs has led to a focused effort on two aspects:

  • Understanding the origins and attributes of natural fracture systems in shales
  • Understanding the interaction of hydraulic fracture treatments with natural fractures

Natural fractures can form in shales at many different times during burial and uplift. The mechanical properties that control natural fracture attributes can be markedly different for different fracture sets, depending on their timing relative to diagenesis. We are using our understanding of the linked chemical and mechanical processes gained from studies in sandstones and carbonates to adopt the same approach in shales. The details of the diagenetic processes are different in shale but the principle of interdependence of chemical and mechanical processes is common to all rock types. The traditional idea that it is the open fractures in a fractured reservoir that are important for production must be modified when dealing with shale-gas reservoirs. Gale et al 2007 showed how interaction of hydraulic fractures with sealed natural fractures is an important consideration. We are currently undertaking geomechanical modeling of these interactions both at the individual fracture interaction scale using XFEM techniques, and also at the interwellbore scale using JOINTS (in house software developed by Jon Olson and available to FRAC members).

Predicting Reservoir Potential in Deep, Low Permeability Sandstones

A key to unlocking the natural gas resource for the future global energy economy lies in successfully targeting effective reservoir rocks in low-porosity, low-saturation, fractured, and heterogeneous rock systems.  This research will create a robust, accurate, and testable procedure for predicting variations in porosity and permeability in deep, tight sandstones. A unique aspect is that rock mass predictions will explicitly include effects of fractures by combining an innovative numerical model for predicting sandstone porosity and permeability, new models for predicting rock mechanical properties through time and space, and a successful computational model for predicting fracture growth patterns. In deep, nonconventional plays, better predictions are key to locating and producing hydrocarbons economically. Our research will provide new geologic system models and exploration concepts that will help find new and overlooked fairways for oil and gas production.  Better interwell characterization will also allow for improved reservoir management, leading to maximum economic recovery of hydrocarbon resources.

Multiazimuth Seismic Diffraction Imaging for Fracture Characterization in Low-Permeability Gas Formations

Natural fractures provide pathways for the flow of gas to hydraulic fractures and to the well bore in many reservoirs. Despite progress in completion technology, prediction and detection of natural fractures prior to drilling or prior to well completion have remained elusive. This project develops novel techniques of predicting fracture occurrence and their attributes by combining seismic tools, fracture modeling, and fracture characterization based on wireline sampling techniques.

The development phase of our project (Phase 1) will create a novel diffraction-based method of detecting and characterizing background fractures and small faults. At the same time we will advance geomechanical simulation of natural fracture patterns and use these realistic fracture patterns, and patterns drawn from outcrop analogs, to calibrate the seismic method according to the realistic heterogeneity that we have shown to exist in low-permeability gas formations.

This aspect of the study will allow us concurrently to advance the unique core (rock sample) based methods we have been developing in order to verify and calibrate seismic methods for fracture characterization in real low-permeability gas formations. The validation/demonstration phase (Phase 2) will follow, in which the Phase 1 strategy will be put to practical test on real data sets and verified in the field. This phase will involve using our new approach to processing seismic data and our enhanced sidewall-core-based verification techniques to collect relatively dense subsurface fracture data throughout the seismic volume.

The techniques of natural fracture prediction and characterization developed in this project are expected to lead to more targeted completion strategies and optimized well spacing, with resultant reduction in water and land use for well development.

The multidisciplinary project team includes research staff and faculty at the Bureau of Economic Geology, the Department of Petroleum and Geosystems Engineering, and the Department of Geological Sciences at The University of Texas at Austin.

For more information on this aspect of the program, see the Geophysics section of the site and 2009 FRAC meeting slide set.

Deformation bands and compaction localization

Deformation bands are planar structures accommodating shear, compaction, or dilation in sand and porous sandstone. Deformation bands typically occur in sets and are preferentially cemented over the host rock, thus forming baffles to fluid flow and imparting a permeability anisotropy to clastic reservoirs. In production settings, it is believed that deformation bands can result in a directional reservoir response not unlike that of fractured reservoirs.

Current FRAC research focuses on the following aspects of deformation bands:

Quantification and modeling of mechanical and chemical porosity reduction: We are investigating the type of diagenetic reactions occurring in deformation bands, the occurrence of these reactions as a function of depth, lithology, and diagenetic environment, and their effect on fluid flow properties of deformation bands. In combination with kinetic models of cement growth and structural investigations, this research intends to provide tools for predicting the effect of deformation bands on the permeability structure of faults and clastic reservoirs containing sets of deformation bands.

Compaction localization and reservoir quality: Localization of compaction into planar compaction bands has been described from several sandstone outcrop locations and from deformation experiments. Our current research investigates the effect of compaction localization on reservoir quality and its implications for porosity depth trends in sandstones and for production-induced formation damage and subsidence. We reconstruct loading conditions under which compaction localization occurs, and quantify the extent of porosity reduction attributable to mechanical porosity reduction and chemical cementation.

Fault deformation processes and flow properties

Faults may act as reservoir seals and preferred flow conduits depending on a variety of parameters, including fault rock properties and their spatial distribution within a fault zone, loading conditions, and slip history. Currently accepted industry practice relies on single-parameter fault seal algorithms for predicting fault seal for exploration and production. Our recent work has shown that these single-parameter algorithms can result in erroneous predictions of fault seal properties due to an overly simplistic assumption about fault gouge generation. Current research attempts to follow a multi-parameter approach that is based on a process-based understanding of faulting mechanisms, fault geometry, and fault permeability structure. By integrating field observations with analyses of fault rock composition, texture, permeability, and capillary properties, we intend to derive a prediction algorithm based on stratigraphic, tectonic, and diagenetic input parameters suitable for fault seal prediction.

Predicting Fracture Porosity Evolution in Sandstone

The goal of this research is to develop an understanding of how fracture growth and diagenetic alteration interact to systematically create and destroy fracture porosity. Our initial objective will be to study a key link between mechanical and chemical processes in opening fractures. Specifically, a new theory of quartz cementation postulates that the rate-limiting step for quartz cementation is precipitation, with supply and transport being of secondary importance. We will test the hypotheses that this cementation process governs evolution of (1) fracture porosity and (2) fracture growth velocity (the subcritical crack index), which, in turn, controls many aspects of fracture pattern development. Despite the important influence of fracture systems on fluid flow, our understanding of the properties of these systems and how they evolve in sedimentary basins is exceedingly meager, owing in part to formidable challenges in collecting meaningful samples of fracture patterns A practical benefit of our fundamental research is that it will lead to predictions of linked structural and diagenetic attributes, therefore potentially increasing the range of samples that provide meaningful fracture information.   

High temperatures and reactive fluids in sedimentary basins dictate that interplay and feedback between mechanical and geochemical processes could significantly influence evolving rock and fracture properties. Moreover, microstructure observations demonstrate that fracturing and diagenesis are linked processes in a wide range of formations, basins, and tectonic settings. Yet we lack fundamental understanding of how these processes are linked. Until we understand how these processes are linked we cannot hope to develop truly predictive models of fracture systems.

We are studying mechanical and diagenetic feedback loops using new models of cementation, improved measurement methods of key mechanical properties, advanced fracture-mechanics-based fracture growth modeling, and high-resolution cement and microstructure quantification. This cross-disciplinary research will result in a fundamental advance in our understanding of how the diversity of natural fracture patterns evolves and better predictions of fracture pattern attributes in the subsurface where sparse sampling is the rule.

For more information on this effort see the Structural Diagenesis section of the web site.


Companies participate in this Industrial Associates program through an annual subscription. Research results are shared equally among supporting companies at annual review meetings and through our private web site.

Research Planning and Reporting
Each year the annual research plan is discussed and approved by the Members. Our private Website is an important part of our information transfer strategy. The private side of the project Website is extensive and frequently updated.

Mentoring and Case Studies
Interaction with the technical staff of our sponsoring companies allows us to test our concepts and methods on real problems while assisting sponsors in developing new reserves. Sponsors are encouraged to contact us with projects that could be mutually beneficial.

New members are welcome to join at any time.

Meeting Schedules
The annual Research Meeting is generally held sometime between late spring and early fall and typically has an associated field trip. The 2008 meeting was held in Santa Barbara, in October with a field trip exploring the Monterey Fm.  We also schedule Applications Meetings, which involve teaching of methods, software, practical exercises using case study data, etc. These meetings may be linked to field trips. In addition, we can meet individually with Members either in Austin or at Members offices to discuss or review case studies or to provide background briefings or training for staff.

During the year, there are various other single-issue technical meetings scheduled in Austin or Houston that Members are welcome to attend. These meetings are announced on the private web site.

Selected FRAC Papers

Late opening-mode fractures in karst-brecciated dolostones of the Lower Ordovician Ellenburger Group, West Texas: recognition, characterization, and implications for fluid flow Gale, J. F. W., and Gomez, L. A., 2007, AAPG Bulletin, v. 91, p. 1005–1023.

Natural fractures in the Barnett Shale and their importance for hydraulic fracture treatments Gale, J. F. W., Reed, R. M., and Holder, Jon, 2007, AAPG Bulletin, v. 91, no. 4, p. 603–622.

Obtaining fracture information for low-permeability (tight) gas sandstones from sidewall cores Laubach, S. E., and Gale, J. F. W., 2006, Journal of Petroleum Geology, v. 29, no. 2, p. 147–158.

Modeling coupled fracture-matrix flow in geomechanically simulated fracture networks: Philip, Z.G., Jennings, J.W., Olson, J.E., Laubach, S.E., and Holder, J., 2005, Society of Petroleum Engineers Reservoir Evaluation & Engineering, v. 8, no. 4 (August issue).

Are open fractures necessarily aligned with maximum horizontal stress? Laubach, S. E., Olson, J. E., and Gale, J. F. W. 2004, Earth & Planetary Science Letters, v. 222, no. 1, p. 191-195.

Coevolution of crack-seal texture and fracture porosity in sedimentary rocks: cathodoluminescence observations of regional fractures: Laubach, S. E., Reed, R. M., Olson, J. E., Lander, R. H., and Bonnell, L. M., 2004, Journal of Structural Geology, v. 26, no. 5, p. 967-982.

Improving fracture permeability prediction by combining geomechanics and diagenesis: Olson, J.E., Laubach, S.E., and Lander, R.H., 2004, North American Rock Mechanics Symposium, ARMA/NARMS 04-563,

Sublinear scaling of fracture aperture versus length: an exception or the rule?: Olson, J.E., 2003, Journal of Geophysical Research v. 108, no. B9, 2413, doi:10.1029/2001JB000419.

Practical approaches to identifying sealed and open fractures: Laubach, S.E., 2003, AAPG Bulletin, v. 87, No. 4, (April 2003), 561-579.

Specifying lengths of horizontal wells in fractured reservoirs: Gale, J.F.W., 2002, Society of Petroleum Engineers Reservoir Evaluation and Engineering, Paper No. SPE 78600, 266–272.

Estimation of fracture orientation and relative intensity using azimuthal variation of P-wave AVO responses and oriented core data in the Tacata Field, Venezuela, Montoya, P., Fisher, W., Marrett, R., and Tatham, R., 2002, SEG Expanded Abstracts, 2002, AVO2 Case History Section, Salt Lake City, 261-264.

Genesis and controls of reservoir-scale carbonate deformation, Monterrey salient, Mexico: Marrett, R., ed., 2001, The University of Texas at Austin, Bureau of Economic Geology, Guidebook 28.

Experimental determination of subcritical crack growth parameters in sedimentary rock: Holder, J., Olson, J.E., and Philip, Z., 2001, Geophysical Research Letters, v. 28, No. 4, 599-602.

Constraining the spatial distribution of fracture networks in naturally fractured reservoirs using fracture mechanics and core measurements, Olson, J. E., Holder, J., Qiu, Y. and Rijken, M., 2001, 2001 SPE Annual Technical Conference and Exhibition, New Orleans, LA, Sept. 30 – Oct. 3.

Brittle deformation in sandstone diagenesis as revealed by scanned cathodoluminescence imaging with application to characterization of fractured reservoirs: Milliken, K.L., and Laubach, S.E., 2000, Chapter 9, Cathodoluminescence in Geosciences, New York, Springer Verlag, 225-243.

Power-law scaling of natural fractures in rock: Marrett, R., Ortega, O.O., and Kelsey, C., 1999, Geology, v. 27, 799-802.

Aggregate properties of fracture populations: Marrett, R., 1996, Journal of Structural Geology, v. 18, No. 2/3, 169-178.

Contact Information

Steve Laubach — Phone: (512) 471-6303 or (512) 471-1534 (BEG Operator)

Julia Gale — Phone: (512) 232-7957 or (512) 471-1534 (BEG Operator)

Randy Marrett — Phone: (512) 471-2113 (Department of Geological Sciences)

Jon Olson — Phone: (512) 471-7375 (Department of Petroleum and Geosystems Engineering)

Peter Eichhubl — Phone: (512) 475 8829 or (512) 471-1534 (BEG Operator)

Eric Potter — Phone: (512) 471-7090 (Bureau of Economic Geology)

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