Rocky Mountain Laramide basins are projected to contain large amounts of natural gas in low permeability reservoirs. The gas reservoirs are compositionally immature, lenticular sands of Cretaceous and younger age within a variety of trap settings. Gas production is often relatively dry with respect to associated water. Reservoir models developed from core and log based petrophysics are often at odds with reservoir descriptions based on long term wellbore pressure build-up tests and production history matching. After more than twenty years of production operations, producible water is increasingly encountered and represents a significant paradox with respect to historical visions of the deep, geopressured basinal areas holding little moveable water.

Resolution of this paradox is a key barrier to improved resource assessment, successful exploration and efficient development operations. To address this barrier, we have studied the chemical nature and occurrence of the produced waters and incorporated our observations into a conceptual reservoir model. Our goal is to develop a model that achieves balance across earth science and engineering disciplines and can be applied to improve resource assessment, exploration and development of these low permeability reservoirs.

Bounding requirements for the conceptual model:

1. The model must honor generally accepted principals of geology, petrophysics, rock mechanics and reservoir engineering.
2. Produced waters, in general, reflect the environment of deposition of their host interval and show little evidence of mass movement.
3. Where the produced water chemistry does not reflect the host rock, its presence and producibility is presumed to reflect the presence of a permeability system sufficient for its movement.
4. Gravity segregation of hydrocarbon and water, although not universal, exists in many fields.
5. Bulk wellbore scale production permeabilities (BHPBU and reservoir simulation) are often 5-100 times higher than would be predicted by classical petrophysical interpretation of reservoirs penetrated in wellbores.

These constraints can be accommodated in a reservoir model using a dual permeability, multiple porosity approach. Beyond the simple construction of such a model, however, and before its effective widespread extrapolation; one must understand the geologic process by which it formed.

From our study of water production, experience and literature review, we hypothesize that the processes of tight gas reservoir development (post deposition) within the Rocky Mountain area can be broadly divided into two phases depending on whether mean confining stress on the reservoir is increasing (Phase I) or decreasing (Phase II). The determinants of mean stress that vary through time are burial (lithostatic and thermoelastic components), pore fluids (poroelastic component), and tectonic (remote stress from tectonic activity). We see temperature (from burial) and stress history (lithostatic and tectonic), acting on the diverse lithologies present within the existing basin fill, as key drivers in the mechanical and chemical development of effective tight gas reservoirs.

Temperature cycles associated with burial and uplift of reservoir sediments are one of the major factors responsible for developing permeability in the reservoirs. Published data show quartz, a major constituent of sandstone reservoirs, as one of the more thermally sensitive minerals commonly found in clastic reservoir rocks. Calcite and orthoclase are also thermally sensitive. Grains of these materials expand and contract with cycles of temperature rise and fall during burial and uplift. Warpinski (1989) noted the large impact of thermally generated compressional stresses and associated strain during burial. A corresponding extensional cycle can be postulated to occur during uplift, acting initially at the grain margins and later at bed scale as intra-bed extensional stresses accumulate. In his Pieance Basin analysis, Warpinski (1989) found the strains generated by temperature effects were the same order of magnitude as inferred tectonic strains.

Regional tectonic processes play a multi-faceted role in the development of tight gas reservoirs. Along with profoundly affecting the basin development, subsidence, stratigraphy and structure, they probably have a diagenetic impact on the sediments. If compressive stresses induced during burial crush grains, and promote pressure solution, it is likely basin shortening will as well. Significant differential lateral stress will preferentially compress the sediments, imparting a weak fabric of planar compressional strain features. These planar strain fabrics will be oriented generally perpendicular to the paleo principal horizontal stress. Laboratory experiments have shown that mortar, when allowed to solidify under stress, will fracture perpendicular to the applied principal horizontal stress when the stress is released. At the basin scale this phenomenon would yield coplanar compressional and extensional features and could potentially create confusion when unraveling local structural fabric and timing.

Visualizing trends of stress increase and decrease through time can improve understanding of event timing in a dynamic system. Bourne et al (2001) offers a reformulated and simpler method to visualize the interplay of mean versus differential stress on rocks than the more traditional Mohr circle. Using a combined Griffith-Coulomb failure criterion and a simple cross-plot of normalized mean stress vs. maximum shear stress they were able to delineate regions of stability, extensional and shear failure. Moreover, by plotting a time series of stress ratios, they demonstrated that the ratios favorable for extensional failure and their trends of change through time made it unlikely that regionally significant extensional failure would occur during times of increasing mean stress. This view is quite consistent with Warpinski’s observation regarding the importance of temperature in generating stress during periods of increasing burial. Increased thermoelastic stresses during burial will most likely offset any increasing pressure from gas generation, at least until the onset of uplift.

Phase I tight gas reservoir development begins with the deposition of the reservoir/source system and ends with the system at maximum temperature and burial depth. Depositional mineralogy, grain size, texture, sand continuity and primary porosity are determined by the provenance and depositional systems active at periods in the basin history. These components play important roles in the chemical and mechanical evolution of the reservoir. Hydrocarbon generation occurs during the later stages of phase I and peaks near the maximum depth of burial. The reservoir sediments are at minimum porosity, maximum pore throat constriction due to cementation, compaction, and pressure solution.

Phase II tight gas reservoir development begins with initiation of uplift, thermal and lithostatic stress release and ends with a dual permeability, dual (and possibly triple) porosity reservoir that may or may not exhibit recognizable gravity segregation. Hydrocarbon generation and intraformational thermoelastic stresses decline as temperatures decrease. Rock strength declines with net confining stress reduction. Effective porosity and permeability increase (particularly in quartz rich sediments) as microfractures develop along the margins of shrinking quartz grains (“tabular pore throats”) and reconnect previously isolated primary porosity. At some point, decreasing rock strength, net confining stress; and remnant overpressure combine to satisfy extensional failure criteria, initiating brittle, extensional fracturing in coarser clastic facies. Clay-rich ductile facies adjust to the changing conditions more rapidly and remain as potential seals. Remobilization of fluids (gas, water) begins with gas expanding to fill developing pore space and increasing its saturation with respect to water. Tectonic activity along basement faults is common during Phase II, potentially disrupting the lateral continuity of ductile sealing facies and allowing movement of hydrocarbons and waters along faults. The increasing mobility of fluids in larger pore throats allows gravity segregation of gas and water within the reservoirs. Changing temperature, pressure, and mobility of waters across bed boundaries alters the stability fields of existing mineral assemblages and enables development of secondary porosity, further enhancing permeability in some areas.

Categorization of basin history into periods of increasing and decreasing mean stress provides an additional filter to allow effective organization of apparently conflicting earth science and engineering observations regarding tight gas reservoirs. This organizational strategy promotes a balanced approach to understanding tight gas reservoir development.

This work is a component of a larger study supported by the Department of Energy under contract DE-FC-02NT41437 “Identifying and Remediating High Water Production Problems In Basin Centered Formations” as part of their program to ensure economic future supplies of gas.

References

Bourne, S.J., and E.J.M. Willemse, 2001, Elastic Stress Control on the Pattern of Tensile Fracturing Around a Small Fault Network at Nash Point, UK., Journal of Structural Geology 23, p 1753-1770.

Warpinski, N.R., 1989, Elastic and Viscoelastic Calculations of Stresses in Sedimentary Basins, SPE Formation Evaluation, vol. 4, p 522-530.

Copyright ©2005. The American Association of Petroleum Geologists. All Rights Reserved.