Structural geology and geomechanics are applied to energy exploration and production
Dr. David A. Ferrill is director of the Earth, Material and Planetary Sciences Department. He is a structural geologist with international research experience in various tectonic regimes and oil and gas exploration. Dr. Alan P. Morris, a staff scientist, is a structural geologist with expertise in quantitative analysis of rock deformation. Dr. Kevin J. Smart, a principal scientist, is a structural geologist with cross-training in computational solid mechanics. Ronald N. McGinnis, a senior research scientist, is a structural geologist with expertise in characterizing mechanical stratigraphy and the control it has on deformation. All are with the Earth, Material and Planetary Sciences Department of the Geosciences and Engineering Division at Southwest Research Institute.
Rock strata often are non-uniform and may contain folds, faults and other deformation.
A significant percentage of total faulting may be below the detection limit, as shown in the graph.
Faults too small to observe using traditional seismic technology, such as those marked in red, nevertheless may be important to the formation and performance of oil and gas reservoirs.
This photograph shows a vertical slice through a model of extensional faulting that uses unconsolidated sand to simulate brittle rock. Physical analog modeling is useful for simulating fault systems.
Red lines show faults on a field photograph from an SwRI study of the plunging Bargy anticline in Haute Savoie, France.
This image shows 2-D finite element simulation of the Bargy anticline with contours of minimum (upper diagram) and maximum (lower diagram) principal strain magnitudes (red=extension, blue=contraction).
Slip tendency analysis of three fault surfaces illustrates that minor fluctuations in fault orientation result in significant changes in slip tendency within a homogeneous stress state. Slip tendency can correlate with fault zone permeability and serve as an indicator of fault leakage, migration pathways or areas at high risk for loss of circulation during drilling.
This conceptual model of a plunging fold shows opposing geologic forces at work, such as extension at the outer arc compared to contraction at deeper locations.
After more than 150 years of oil and gas production following the first successful oil well in Pennsylvania in 1859, most of the easy-to-produce oil and gas reservoirs have already been found. New hydrocarbon discoveries tend to be more structurally complex and located in tighter rock, at greater depths or in deeper water. Finding these harder-toreach resources, and then producing from them, calls for ever-increasing expertise in characterizing and understanding the influences of geologic structures on the deposition and deformation of reservoir, seal, and source strata.
Over the years, new and more sensitive seismic technologies have been developed to reveal formerly unrecognized subsurface geologic structures. In many cases, however, the products of geologic deformation which occur as faults, folds and fractures are still below the detection limits of 3-D seismic reflection data, thus requiring a geologist to predict or infer subseismic-scale deformation. To be successful in these increasingly challenging exploration and production environments, petroleum geologists need higher resolution tools, but perhaps more important, they need sophisticated training to aid interpreters as they analyze the data generated by the improved hardware and software tools. A team of geologists from Southwest Research Institute (SwRI) has developed approaches to aid oil and gas exploration and improve the prospects for successful production from unconventional reservoirs.
The process involves collecting data to characterize the natural deformation, rock mechanical properties and stress environments; studying outcrops to characterize reservoir rocks or their analogs; analyzing stress fields, both past and present, and predicting stress changes resulting from production activities such as hydraulic fracturing and pressure declines; and performing geomechanical analyses using physical analog and numerical modeling techniques.
Stress and geomechanical analyses allow geologists to leverage limited static data and thus track dynamic stress and deformation over time. The time scales range from geologically instantaneous seismic deformation caused by earthquakes or induced hydraulic fracturing, to longer-term production (field lifetime) scales, and ultimately to geologic time scales.
The basics of reservoir analysis
Geologic structure, stress and fluid pressure conditions, and geomechanical behavior of rock are key elements in determining trap, reservoir and charge in hydrocarbon systems. Conventional hydrocarbon traps are commonly formed by geologic structures such as domes, anticlines, and sealing faults. Fracture and fault systems can also compromise trap integrity and may be difficult or impossible to detect. So-called unconventional resource plays, where the source and reservoir rock are the same, are becoming increasingly important in hydrocarbon exploration and production. These unconventional plays are typically dependent on induced fracturing (“fracking”) for their economic viability, and therefore the presence or absence of natural faults and fractures, the ambient stress state, and the mechanical characteristics of the reservoir rocks are critical factors in planning effective production strategies.
Reservoir quality, especially in tight (low porosity) reservoir rock, is often enhanced by open natural fractures. In contrast, small-displacement sealing faults can significantly reduce reservoir quality and compartmentalize hydrocarbon reservoirs. Increasing fluid pressure to stimulate hydraulic fracturing in unconventional shale or tight sand reservoirs takes advantage of in situ stress and fluid pressure conditions to reactivate natural fractures and induce new fractures to create or enhance fracture permeability. In contrast, declining fluid pressures over a reservoir’s productive lifetime can cause naturally permeable faults and fractures to close or lose their permeability, thus reducing overall reservoir permeability or compartmentalizing the reservoir.
In many cases, hydrocarbon generation and migration into a reservoir depends on stress conditions, geomechanical properties of rock, deformation processes, and geologic structure. These conditions commonly combine to provide pathways for migration of hydrocarbons from the site of source rock maturation, sometimes called the “kitchen.” In unconventional reservoirs, the kitchen is also the reservoir, and conditions that are favorable for migration are detrimental to the richness of the reservoir because they allow some hydrocarbons to escape.
Although, with virtually no significant exceptions, oil and gas reservoirs are buried beneath the earth’s surface, direct analogs of the rock types and structural features (folds, faults and fractures) can be observed first-hand somewhere at the earth’s surface. In the spirit of H.H. Read’s observation that the best geologists are the ones who have seen the most rocks, it is essential to develop an understanding of reservoir behavior by observing and analyzing rocks in the field. To this end, geologists inform their models by studying the closest field analogs to the reservoir rocks they wish to understand.
Geomechanics is the application of mechanical (or rock mechanical) principles to geologic problems. Although geomechanical modeling often invokes the idea of computer-based analysis, the structural geology community has a well-established record of using physical analog as well as numerical modeling techniques to understand structural geology and geomechanics problems. Therefore, these two approaches should be thought of as complementary.
Physical analog models typically employ a model material or materials whose behavior in the lab is analogous to some material in nature. Among the most commonly used materials for studying geologic phenomena are dry sand, wet clay and silicone putty. Physical analog models have the advantage of allowing very large strains to develop and failure (fault rupture) to occur. They are especially well-suited to the study of complex three-dimensional structures as they form, and they can provide powerful conceptual insights. The primary disadvantages are the difficulty in building multiple near-identical models, which makes parametric study challenging, and the limitations on extractable information. For example, the geometry and developmental history of a structure are available, but quantitative stress values are not.
Numerical models also have a long history of use in understanding structural geology and geomechanics problems. Numerical models offer the advantage of providing detailed information such as stress, strain, temperature and pore pressure throughout the entire evolution of the structure, both temporally and spatially. In general they are well-suited to parametric studies where one or more components are systematically varied; for example, material properties and loading conditions. Even with recent advances in computer power, however, complex three-dimensional numerical models are still difficult to construct and may take days or even weeks to run.
Finite element modeling is particularly powerful for oil industry problems because it allows modeling of systems across all scales and time frames, simulating large displacements and strains, implementing diverse material model (viscous, elastic, plastic, viscoelastic or elastic-plastic) behavior, simulating permanent deformation and tracking realistic stress, strain and fluid pressure.
Major strides have been made in recent years in simulating oilfield-scale structures, calibrating models against quantitative measures of geometry, deformation, or stress and fluid pressure information and testing the influence of variables such as rock strength and the role of bedding plane slip. These results have demonstrated that finite element forward models can replicate large-scale geometries and patterns of smaller-scale deformation within layers. Results have also highlighted the key role that mechanical layering and bedding plane slip can have on deformation, and the importance of factoring this into numerical simulations. New results are demonstrating the utility of finite element modeling to simulate induced hydraulic fracturing in mechanically layered rocks, including the generation of tensile and shear failure.
Structural geology, stress and geomechanical analysis are important components of oil and gas industry exploration and production. This is especially true as the industry enters increasingly complex and challenging geologic environments both conventional and unconventional. Sound understanding of structural geology and geomechanics concepts can be developed through classroom and outcrop studies. Site-specific structural geologic and geomechanical investigations are often warranted to address exploration and production challenges, and the selection of the approach(es) depends on the problem, setting and available data. Mapping is often the first order of business, and many problems can be preempted by careful interpretation, consideration of multiple working hypotheses for areas of poor data, and better mapping. It is never too early in a project to start thinking about subseismic scale structure, mechanical stratigraphy, stress and fluid pressure conditions, and perturbations to structural geologic and geomechanical conditions that will occur due to injection and extraction processes. Efforts to understand these factors should start simple, start early in the project and be updated using additional data as they become available.
We appreciate the thoughtful review by Dr. Gary Walter. Portions of this work were supported by several Southwest Research Institute Internal Research and Development projects.
SwRI program illuminates Eagle Ford geology for oil and gas producers
Petroleum-bearing strata can be better understood by viewing locations where they outcrop, such as this exposure of the Boquillas Formation, also known as the Eagle Ford, in a road cut near Del Rio, Texas.
Before risking millions to drill a new well, oil company geologists might wish they could peer through thousands of feet of solid rock to better understand what lies below.
Through a program managed by Southwest Research Institute’s (SwRI) Geosciences and Engineering Division, geologists are studying the deeply buried South Texas formation known as the Eagle Ford Shale by visiting the places where it is exposed at the ground surface.
The Eagle Ford Formation is a highly productive oil and gas reservoir. In the industry, it’s a type known as “unconventional,” which generally means that the source rock for the hydrocarbons is also the reservoir, a situation sometimes called self-sourced. Variability in mineralogy, natural fracturing, and ambient stress state influence the industry’s ability to hydraulically fracture the reservoir, therefore making it a challenge to develop an optimal drilling strategy.
Geologists want to know how pre-existing ‘natural’ fractures might influence hydraulic fracturing and well performance, what types of fractures are likely to be produced, how far they will extend and what volume of rock a well may be able to produce from. The answers to these questions are crucial to drilling strategy.
To help answer such questions and understand the fundamental relationships between stratigraphy, natural fracturing, and stress conditions, SwRI in 2011 organized a joint industry project for producers in the Eagle Ford and associated formations.
Midway through its first two-year phase, the Eagle Ford Joint Industry Project includes eight member oil companies. It offers geologists a chance to view outcrops of the Eagle Ford and associated formations at locations in West and South Central Texas.
From studies of those outcrops, investigators analyze the stratigraphy and mechanical behavior of the strata and natural deformation including faulting, folding, and fracturing, as well as past and present stress conditions. The analyses help producers understand the pre-existing natural deformation, as well as the important role that mechanical stratigraphy plays in controlling distribution and style of faulting, fracturing and related deformation.
In addition to outcrop-based analyses, the project includes geomechanical simulation of natural and induced fracturing to better understand the behavior of the Eagle Ford and other mechanically layered or heterogeneous self-sourced (unconventional) reservoirs. These results are transforming how companies understand and plan development in the Eagle Ford.
Membership fee for the consortium is $75,000 for each twoyear phase.
Contact Ferrill at (210) 522-6082 or firstname.lastname@example.org.