Travis Peak Research Articles

Geologic characterization of the Lower Cretaceous upper Travis Peak and Pettet Formations in the Wright Mountain field, Smith County, East Texas basin: Potential reservoir analog for other Travis Peak and Pettet strata

The Wright Mountain field in Smith County, Texas, is a tight carbonate reservoir that produces from the Lower Cretaceous Pettet Formation. The Pettet Formation is dominantly made up of cyclic shallow-water shelfal carbonates associated with skeletal oolitic shoal complexes. These shoals are widespread hydrocarbon-reservoir targets, have poor to fair matrix reservoir quality, and are commonly sealed by transgressive argillaceous lime mudstones and wackestones. Complex regional paleotopography has significant impact on the regional distribution of these shoal bodies and overall depositional patterns. This investigation, therefore, aims to characterize the Pettet Formation and underlying fluviodeltaic Travis Peak Formation in the Wright Mountain field, located on the western flank of the Strickland High near the northeastern margin of the East Texas Basin, to assess reservoir parameters and to compare depositional patterns to existing shoal-complex studies centered on the top of the paleohigh in Rusk County. The Pettet section in Smith County consists of three fourth-order sequences (Pettet A–C), each of which shoals upwards into a shallow-water, high-energy environment near or within shoal complexes. The best reservoir lithofacies are the mixed skeletal-ooid and skeletal grainstones, as observed elsewhere in the Pettet Formation in Rusk County. However, texture and biota vary in the Wright Mountain field area as compared to the Rusk County area as there is abundant evidence of reworking and resedimentation in the Wright Mountain field area, suggesting a different depositional setting perhaps related to off-shoal deposition or greater depositional dip. Therefore, this field characterization study is important for constructing a regional depositional model and can be applied as an analog for equivalent systems with similar lithofacies and pore networks elsewhere in the northern Gulf of Mexico.

Displacement Efficiency in Tight Sandstone Based on Fractional Flow Curve Using Relative Permeability Data

In tight gas sandstone, relative permeability is an essential special core analysis dynamic test that can be used to estimate injectivity, secondary recovery, production rate, reservoir simulation, residual gas saturation, and effective water management. Having about 65% of hydraulic fracturing fluid not to flow back and stay in the reservoir results in having the tight sandstone gas reservoir to involve multi-phase flow, namely water and gas. During the hydraulic fracturing job both imbibition and forcibly imbibition processes take place while during fracturing fluid cleanup and gas production drainage flow becomes dominant.
 The steady state flooding process was used to measure the relative permeability curves for tight sandstone core sample collected from Travis Peak Formation at a depth of 8707 ft. The measurement process involved the performance of a series of steady state experiments with different gas-water injection ratio. The fractional flow curve has been plotted, based on the measured relative permeability, and used to calculate the displacement efficiency for the flow through such type of tight porous media. The measurement showed relatively high irreducible water saturation (31%) and low residual gas saturation (6%). The measured gas relative permeability decreased slowly at a constant rate with increased wetting fluid saturation. The obtained fractional flow curve does not follow the s-shape behavior observed in conventional reservoir. The obtained results showed that displacement efficiency can be enhanced by increasing water viscosity.

A history of pore water oxygen isotope evolution in the Cretaceous Travis Peak Formation in East Texas

Abstract Oxygen isotope analyses of diagenetic cements can provide detailed evidence of sedimentary burial processes and conditions, as the δ18O values of precipitating minerals reflect contemporaneous local δ18Owater and temperature conditions. Uncertainties in the timing and rates of pore water δ18O evolution in sedimentary basins can complicate interpretation of these records. Fracture-bridging (0.5–1 mm) quartz cements observed in sandstones of the Cretaceous Travis Peak Formation in the East Texas basin show clear growth-zoning by cathodoluminescence and contain detailed fluid inclusion records of temperature that make them excellent candidates for interrogating prolonged histories of basin temperature and the evolution of δ18O in basin pore water. New secondary ion mass spectrometer (SIMS) δ18Oquartz isotopic data from fluid inclusion-rich quartz bridges in Travis Peak sandstones record a steady increase of pore water δ18O values from ∼5 to 7‰ (VSMOW; Vienna Standard Mean Ocean Water) as the sandstone warms from ∼130 to 150 °C. To help evaluate whether this trend could be generated solely from local water-rock interactions in response to burial compaction, a one-dimensional closed system isotopic burial model was created to simulate how δ18Owater values change in a quartz-dominated sandstone during diagenesis. Using both directly measured and inferred rates of Travis Peak compaction, the magnitude of change in δ18Owater that we calculate from quartz bridge geochemistry cannot be reasonably modeled solely by local quartz mechanical compaction, pressure solution, and cementation processes, necessitating significant fluxes of silica and high-δ18O water from outside of the sandstones prior to maximum burial. This indicates that even units which appear surrounded by significant barriers to fluid flow (i.e., mudrock-bounded channel sandstones) may have been infiltrated and diagenetically modified by large fluxes of fluid on geologic time scales.

The use of noble gas isotopes to constrain subsurface fluid flow and hydrocarbon migration in the East Texas Basin

The migration of hydrocarbons from source-rock to reservoir is a critical stage in petroleum system evolution. However, as migration occurs along confined pathways over geologically rapid timescales it is challenging to place quantitative constraints on migration behaviour in terms of interaction with other basinal fluids, flux, and lengthscales associated with this process. Due to their inert nature, noble gases are ideal tracers of fluid provenance and physical processes in a variety of subsurface systems, and thus can serve as a potential geochemical indicator of migration distance. The recent proliferation of unconventional hydrocarbon production (i.e., production directly from source-rocks) allows for the analysis of fluids from these strata. Here we present noble gas data from natural gas samples produced from 27 related conventional and unconventional wells within the East Texas basin. These data enable characterisation of fluids during migration from source-rock to conventional reservoir. Unconventional gases and fluids are produced from the Haynesville shale (n = 8), and conventional gases and fluids are sourced from the overlying Cotton Valley (n = 5), Travis Peak (n = 9), and James Lime (n = 5) formations. Samples consist primarily of methane (>70%), with small contributions from longer-chain hydrocarbons, and other gases including CO2 and N2. Atmosphere-derived 36Ar, which is introduced into natural gas accumulations via interaction with groundwater during hydrocarbon generation and migration, is consistently higher in samples that have undergone a greater migration distance from the source interval. Thus, calculated volume ratios of gas-water interaction (Vg/Vw) show a far greater incidence of groundwater interaction in migrated samples. Radiogenically-produced 40Ar is also consistently elevated in migrated samples, despite these reservoirs being located in geologically younger strata. We derive the representative volume of rock required to produce the observed radiogenic 40Ar in each sample and show that samples that have migrated further have acquired radiogenic isotopes from larger volumes of rock. Furthermore, our volumetric parameters derived from atmospheric and radiogenic isotopes are consistent with a simple conceptual model of migration. We quantitatively apply this model to demonstrate that migration occurs along relatively localised pathways. Helium (3He/4He) and argon (40Ar/36Ar) isotopes are correlated and show elevated amounts of mantle-derived 3He and radiogenic 40Ar in migrated samples. We interpret this to represent mixing between a pristine source-rock signature and an endmember characterised by elevated 3He/4He and 40Ar/36Ar, likely representative of mantle-enriched groundwater circulating in the wider hydrogeological basin. Finally, we use an advection-diffusion model to show that enriched mantle 3He in the shallower strata and towards the southern edge of the basin can be explained by influx of mantle helium along the fault-bounded southern edge of the basin over timescales of millions of years. Together these approaches represent the first complete noble gas based characterization of a hydrocarbon system, sampling migration from source-rock to trap. We show conclusively that both atmospheric and radiogenic noble gases are entrained in the hydrocarbon phase during migration and that concentrations scale proportionally with migration distance, as greater volumes of groundwater and host rock are encountered.

Opening-mode fracture systems: insights from recent fluid inclusion microthermometry studies of crack-seal fracture cements

Abstract Overpressuring, tectonic stretching and thermoelastic contraction are all processes that can drive the formation of opening-mode fractures in the subsurface. Recent studies on crack-seal quartz deposits in opening-mode fractures have yielded fluid inclusion microthermometric data, which for the first time allow us to constrain the pressure–temperature conditions under which these fractures formed. Here, we utilize the results from studies in the Lower Cretaceous Travis Peak Formation in the East Texas Basin and the Upper Cretaceous Mesaverde Group in the Piceance Basin to construct stress history models based on mechanical properties, burial history and tectonic setting to evaluate the various driving mechanisms for opening-mode fracture formation. Our results show progress towards separating and independently evaluating these mechanisms. Although high fluid pressure and tectonic stretching can play a major part in the formation of opening-mode fractures, our results suggest that the persistence of fracture growth during uplift could have been strongly influenced by thermoelastic contraction associated with exhumation and cooling. For sandstone reservoirs, thermoelastic contraction will be more pronounced for stiffer, high Young's modulus rocks with higher quartz contents. These models can therefore be used to provide additional insights into the distribution of opening-mode fractures in exhumed basins.

Quartz c-axis orientation patterns in fracture cement as a measure of fracture opening rate and a validation tool for fracture pattern models

We evaluate a published model for crystal growth patterns in quartz cement in sandstone fractures by comparing crystal fracture-spanning predictions to quartz c-axis orientation distributions measured by electron backscatter diffraction (EBSD) of spanning quartz deposits. Samples from eight subvertical opening-mode fractures in four sandstone formations, the Jurassic–Cretaceous Nikanassin Formation, northwestern Alberta Foothills (Canada), Cretaceous Mesaverde Group (USA; Cozzette Sandstone Member of the Iles Formation), Piceance Basin, Colorado (USA), and upper Jurassic–lower Cretaceous Cotton Valley Group (Taylor sandstone) and overlying Travis Peak Formation, east Texas, have similar quartzose composition and grain size but contain fractures with different temperature histories and opening rates based on fluid inclusion assemblages and burial history. Spherical statistical analysis shows that, in agreement with model predictions, bridging crystals have a preferred orientation with c-axis orientations at a high angle to fracture walls. The second form of validation is for spanning potential that depends on the size of cut substrate grains. Using measured cut substrate grain sizes and c-axis orientations of spanning bridges, we calculated the required orientation for the smallest cut grain to span the maximum gap size and the required orientation of the crystal with the least spanning potential to form overgrowths that span across maximum measured gap sizes. We find that within a 10° error all spanning crystals conform to model predictions. Using crystals with the lowest spanning potential based on crystallographic orientation (c-axis parallel to fracture wall) and a temperature range for fracture opening measured from fluid inclusion assemblages, we calculate maximum fracture opening rates that allow crystals to span. These rates are comparable to those derived independently from fracture temperature histories based on burial history and multiple sequential fluid inclusion assemblages. Results support the R. Lander and S. Laubach model, which predicts that for quartz deposited synchronously with fracture opening, spanning potential, or likelihood of quartz deposits that are thick enough to span between fracture walls, depends on temperature history, fracture opening rate, size of opening increments, and size, mineralogy, and crystallographic orientation of substrates in the fracture wall (transected grains). Results suggest that EBSD maps, which can be more rapidly acquired than measurement of tens to hundreds of fluid inclusion assemblages, can provide a useful measure of relative opening rates within populations of quartz-filled fractures formed under sedimentary basin conditions. Such data are useful for evaluating fracture pattern development models.

Investigating flow properties of partially cemented fractures in Travis Peak Formation using image‐based pore‐scale modeling

AbstractNatural fractures can provide preferred flow pathways in otherwise low‐permeability reservoirs. In deep subsurface reservoirs including tight oil and gas reservoirs, as well as in hydrothermal systems, fractures are frequently lined or completely filled with mineral cement that reduces or occludes fracture porosity and permeability. Fracture cement linings potentially reduce flow connectivity between the fracture and host rock and increase fracture wall roughness, which constricts flow. We combined image‐based fracture space characterization, mercury injection capillary pressure and permeability experiments, and numerical simulations to evaluate the influence of fracture‐lining cement on single‐phase and multiphase flows along a natural fracture from the Travis Peak Formation, a tight gas reservoir sandstone in East Texas. Using X‐ray computed microtomographic image analysis, we characterized fracture geometry and the connectivity and geometric tortuosity of the fracture pore space. Combining level set method‐based progressive quasistatic and lattice Boltzmann simulations, we assessed the capillary‐dominated displacement properties and the (relative) permeability of a cement‐lined fracture. Published empirical correlations between aperture and permeability for barren fractures provide permeability estimates that vary among each other, and differ from our results, vary by several orders of magnitude. Compared to barren fractures, cement increases the geometric tortuosity, aperture variation of the pore space, and capillary pressure while reducing the single‐phase permeability by up to 2 orders of magnitude. For multiphase displacement, relative permeability and fluid entrapment geometry resemble those of porous media and differ from those characteristic of barren fractures.

Insights into rates of fracture growth and sealing from a model for quartz cementation in fractured sandstones

A new model accounts for crystal growth patterns and internal textures in quartz cement in sandstone fractures, including massive sealing deposits, thin rinds or veneers that line open fracture surfaces, and bridge structures that span otherwise open fractures. High-resolution cathodoluminescence imaging of bridge structures and massive sealing deposits indicates that they form in association with repeated micron-scale fracturing of growing quartz crystals, whereas thin rinds do not. Model results indicate that the three morphology types develop in response to (1) the ratio of the rates of quartz growth to fracture opening and (2) the substantially faster growth rate that occurs on noneuhedral surfaces in certain crystallographic orientations compared to euhedral crystal faces. Rind morphologies develop when the fracture opening rate exceeds two times the fastest rate of quartz growth (along the c axis on noneuhedral surfaces) because growing crystals develop slow-growing euhedral faces. Massive sealing, on the other hand, develops where the net rate of fracture opening is less than twice the rate of quartz growth on euhedral faces because all quartz growth surfaces along the fracture wall seal the fracture between fracturing events. Bridge structures form at fracture opening rates that are intermediate between the massive sealing and rind cases and are associated with crystallographic orientations that allow growth to span the fracture between fracturing events. Subsequent fractures break the spanned crystal, introducing new, fast-growing noneuhedral growth surfaces where quartz grows more rapidly compared to the euhedral faces of nonspanning crystals. As the ratio of fracture opening to quartz growth rate increases, the proportion of overgrowths that span the fracture decreases, and the range in c -axis orientations for these crystals comes progressively closer to perpendicular to the fracture wall until the maximum spanning limit is reached. Simulation results also reproduce “stretched crystal,” “radiator structure,” and “elongate blocky” textures in metamorphic quartz veins. The model replicates a well-characterized quartz bridge from the Cretaceous Travis Peak Formation as well as quartz cement abundances, internal textures, and morphologies in the sandstone host rock and fracture zone using the same kinetic parameters while honoring fluid-inclusion and thermal-history constraints. The same fundamental driving forces, in both in the host rock and fracture system, are responsible for quartz cementation, with the only significant difference within the fracture zone being the creation of new pore space as well as new noneuhedral surfaces for cases where overgrowths span fractures between fracturing events. Rates of fracture growth and sealing may be inferred from fracture cement textures using model results.

Models for guiding and ranking well-to-well correlations of channel bodies in fluvial reservoirs

A probabilistic method has been devised to assess the geologic realism of subsurface well-to-well correlations that entail the lateral tracing of geologic bodies across well arrays with constant spacing. Models of geo-body correlability (based on the ratio between correlatable and penetrated geo-bodies) are obtained from total probabilities of penetration and correlation, which are themselves dependent on the distribution of lateral extent of the geo-body type. Employing outcrop-analog data to constrain the width distribution of the geo-bodies, it is possible to generate a model that describes realistic well-to-well correlation patterns for given types of depositional systems. This type of correlability model can be applied for checking the quality of correlation-based subsurface interpretations by assessing their geologic realism as compared with one or more suitable outcrop analogs. The approach is illustrated by generating total-probability curves that refer to fluvial channel complexes and that are categorized on the basis of outcrop-analog classifications (e.g., braided system, system with 20% net-to-gross), employing information from a large fluvial geo-body database, Fluvial Architecture Knowledge Transfer System (FAKTS), which stores information relating to fluvial architecture. From these total-probability functions, values can be drawn to adapt the correlability models to any well-array spacing. The method has been specifically applied to rank three published alternative interpretations of a stratigraphic interval of the Travis Peak Formation (Texas), previously interpreted as a braided fluvial depositional system, in terms of realism of correlation patterns as compared to (1) all analogs recorded in FAKTS and considered suitable for large-scale architectural characterization, and (2) a subset of them including only systems interpreted as braided.

Advances in PDC Cutter Bits Improve Drilling in Hard, Abrasive Formations

Technology Update About 70% of the footage drilled worldwide is performed with polycrystalline diamond compact (PDC) bits. This percentage is projected to increase with the continued pursuit of hydrocarbons and geothermal energy in more challenging environments. In these more demanding applications, conventional PDC cutting elements have often failed because of formation abrasiveness, impact damage, and thermal fatigue. To improve PDC bit drilling, a tougher, more abrasion-resistant cutter technology is required. An extensive research and manufacturing effort was launched to develop new technology that would enable a cutter to withstand harder, more abrasive formations. Attention focused on manufacturing processes involving diamond sintering and advanced materials development. The initiative resulted in the development of the Onyx II premium PDC cutter, which has significantly improved abrasion resistance and thermal stability. The cutter has been run in the Travis Peak and Cotton Valley formations in east Texas for Devon Energy since 2010 and has generated improved rate of penetration (ROP) results while significantly reducing cost. The new cutter represents an evolution of technology, having been introduced two years after the debut of the first generation of the high-performance shearing element. Development of the first-generation cutter was enabled by the use of a proprietary, two-step high-pressure/high-temperature (HP/HT) manufacturing method that allowed PDC bits to drill more footage at higher ROP. With bits fitted with these cutters, intervals that normally required multiple PDC bits to reach total depth could be drilled in a single run in some cases. Engineering a New Cutter To advance the technology to the next level, a key objective was to develop a tightly packed, high-density diamond structure that would enable the cutter to achieve better wear resistance and improved thermal stability. Experiments with several diamond grit combinations were made. The mixture of base diamond material with different size distributions was evaluated to achieve the best theoretical packing density. The mixture was then sintered using an extreme HP/HT process. The process produced additional diamond/diamond bridging and networking, compared with the existing cutter manufacturing process. Tests have confirmed that the extreme HP/HT process produces a cutter with improved thermal wear resistance capable of retaining a sharp cutting edge for a longer period than previous cutters.

Understanding and Managing Bottomhole-Circulating- Temperature Behavior in Horizontal High-Temperature Wells

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 140332, ’Understanding and Managing Bottomhole Circulating Temperature Behavior in Horizontal High-Temperature Wells - A Case Study Based on Haynesville Horizontal Wells,’ by Keith Trichel, SPE, and John Fabian, SPE, Baker Hughes, prepared for the 2011 SPE/IADC Drilling Conference and Exhibition, Amsterdam, 1-3 March. The paper has not been peer reviewed. While high-temperature (HT) wells have always presented drilling challenges, the recent activity increase in the Haynesville shale along the border of Texas and Louisiana presents an extreme environment for drilling equipment. Along with a high frequency of temperature-related measurement-while-drilling (MWD) and logging-while-drilling (LWD) failures, the profile and architecture of Haynesville wells have provided an opportunity to study and understand the thermal behavior of horizontal HT wells in general. Thereby, well-specific operational guidelines and planning considerations can be implemented to reduce the risk of downhole temperature-related failures. Introduction The Haynesville covers approximately 9,000 sq miles. The Haynesville basin could contain up to 250 Tcf of technically recoverable gas, making it one of the largest gas plays in the USA. Production is from the Bossier and Haynesville shale formations, which correspond in many areas, so the names often are used interchangeably. The Haynesville has average thickness of 200 to 300 ft, and the depth ranges from 10,500 ft in the northwestern part of the basin to 13,500 ft in the southeastern extremities. This play is one of the deepest shale plays, and, therefore, downhole conditions are more difficult. Bottomhole temperatures (BHTs) have been measured on the order of 380°F. A typical Haynesville well requires 35 to 45 days to drill. The intermediate section may be drilled with either water-based mud (WBM) or oil-based mud (OBM), at the operator’s discretion. Soft sediments are encountered in the upper section below surface casing, but very hard and abrasive zones are found in the lower portion when passing through the Travis Peak and Cotton Valley formations. Completing the intermediate-hole section in a single polycrystalline-diamond-compact-bit run is difficult. Most horizontal sections in the Haynesville are drilled with OBM and experience high bottomhole circulating temperatures in the range of 300 to 350°F, mud weights of 15 to 17 lbm/gal, and high stand-pipe pressures of approximately 4,000 psi. The combination of OBM, high temperature, and high solids content in the mud is a challenging environment for downhole motors, but motor failure is not the leading cause of unplanned trips. Often, the high bottomhole circulating temperatures exceed the normal temperature rating of MWD/LWD electronics, typically 302°F. To address this need, some directional-service companies offer specially screened tools rated to 320°F while others offer high-temperature tools rated to 350°F. Even with this technology, recent trends indicate that the leading cause of unplanned trips in the Haynesville is likely to be failure of the MWD/LWD electronics.

A 48 m.y. history of fracture opening, temperature, and fluid pressure: Cretaceous Travis Peak Formation, East Texas basin

Research Article| July 01, 2010 A 48 m.y. history of fracture opening, temperature, and fluid pressure: Cretaceous Travis Peak Formation, East Texas basin S.P. Becker; S.P. Becker * 1Bureau of Economic Geology, The University of Texas at Austin, University Station Box X, Austin, Texas 78713-8924, USA *Current address: ExxonMobil Upstream Research Company, P.O. Box 2189, Houston, Texas 77252-2189, USA. Search for other works by this author on: GSW Google Scholar P. Eichhubl; P. Eichhubl † 1Bureau of Economic Geology, The University of Texas at Austin, University Station Box X, Austin, Texas 78713-8924, USA †E-mail: peter.eichhubl@beg.utexas.edu Search for other works by this author on: GSW Google Scholar S.E. Laubach; S.E. Laubach 1Bureau of Economic Geology, The University of Texas at Austin, University Station Box X, Austin, Texas 78713-8924, USA Search for other works by this author on: GSW Google Scholar R.M. Reed; R.M. Reed 1Bureau of Economic Geology, The University of Texas at Austin, University Station Box X, Austin, Texas 78713-8924, USA Search for other works by this author on: GSW Google Scholar R.H. Lander; R.H. Lander 2Geocosm LLC, 3311 San Mateo Drive, Austin, Texas 78738, USA Search for other works by this author on: GSW Google Scholar R.J. Bodnar R.J. Bodnar 3Department of Geosciences, 4044 Derring Hall, Virginia Tech, Blacksburg, Virginia 24061, USA Search for other works by this author on: GSW Google Scholar GSA Bulletin (2010) 122 (7-8): 1081–1093. https://doi.org/10.1130/B30067.1 Article history received: 05 Apr 2009 rev-recd: 03 Aug 2009 accepted: 24 Aug 2009 first online: 08 Mar 2017 Cite View This Citation Add to Citation Manager Share Icon Share Facebook Twitter LinkedIn MailTo Tools Icon Tools Get Permissions Search Site Citation S.P. Becker, P. Eichhubl, S.E. Laubach, R.M. Reed, R.H. Lander, R.J. Bodnar; A 48 m.y. history of fracture opening, temperature, and fluid pressure: Cretaceous Travis Peak Formation, East Texas basin. GSA Bulletin 2010;; 122 (7-8): 1081–1093. doi: https://doi.org/10.1130/B30067.1 Download citation file: Ris (Zotero) Refmanager EasyBib Bookends Mendeley Papers EndNote RefWorks BibTex toolbar search Search Dropdown Menu toolbar search search input Search input auto suggest filter your search All ContentBy SocietyGSA Bulletin Search Advanced Search Abstract Quartz cement bridges across opening-mode fractures of the Cretaceous Travis Peak Formation provide a textural and fluid inclusion record of incremental fracture opening during the burial evolution of this low-porosity sandstone. Incremental crack-seal fracture opening is inferred based on the banded structure of quartz cement bridges, consisting of up to 700 cement bands averaging ∼5 μm in thickness as observed with scanning electron microscope–cathodoluminescence. Crack-seal layers contain assemblages of aqueous two-phase fluid inclusions. Based on fluid inclusion microthermometry and Raman microprobe analyses, we determined that these inclusions contain methane-saturated brine trapped over temperatures ranging from ∼130°C to ∼154°C. Using textural crosscutting relations of quartz growth increments to infer the sequence of cement growth, we reconstructed the fluid temperature and pore-fluid pressure evolution during fracture opening. In combination with published burial evolution models, this reconstruction indicates that fracture opening started at ca. 48 Ma and above-hydrostatic pore-fluid pressure conditions, and continued under steadily declining pore-fluid pressure during partial exhumation until present times. Individual fractures opened over an ∼48 m.y. time span at rates of 16–23 μm/m.y. These rates suggest that fractures can remain hydraulically active over geologically long times in deep basinal settings. You do not have access to this content, please speak to your institutional administrator if you feel you should have access.

Topographic Irregularities on the Base Zuni Supersequence Boundary and their Initial Cretaceous Sediment Fill, Central Texas

ABSTRACT The Cretaceous-preCretaceous unconformity, i. e., base Zuni supersequence boundary, crops out across much of central and west Texas. Topographic features on the unconformity surface are exhumed along the erosional out-crop edge of the nearly flat-lying Cretaceous strata that overlie the surface within Lampasas and Mills counties, Texas. Digital elevation data displayed as a topographic profile atop Pennsylvanian outcrops adjacent to the Cretaceous outcrop edge indicate that paleotopography was influenced by northwest-dipping Pennsylvanian strata that underlie the unconformity surface. Differential erosion of Pennsylvanian limestone, sandstone, and shale prior to Cretaceous deposition created a trellis network of northeast-trending valleys and divides. Local tectonic features, climate, and rising sea level influenced the nature of the Cretaceous fluvial fill that directly overlies the unconformity surface. The Sycamore Conglomerate is the earliest Cretaceous deposit, and accumulated in a sub-humid or drier climate as a downfilling braided alluvial wedge shed off the Llano Uplift. The Travis Peak Formation, a conglomeratic sandstone, onlaps and disconformably overlies the Sycamore Conglomerate, and was deposited as an aggradational meandering river complex during sea level rise.

Pore Pressure/Stress Coupling and its Implications for Seismicity

Periodic pressure measurements made during the depletion of oil fields and virgin pressure measurements through normally- and over-pressured sequences in sedimentary basins both demonstrate that changes in pore pressure and minimum horizontal stress (σh) are coupled to one another. Pore pressure/stress coupling is predicted by poroelastic theory. Data from the North Sea (Ekofisk Field) and Texas (Travis Peak Formation of east Texas and Vicksburg Formation of south Texas) suggest that σh decreases at approximately 80% and 50% of the rate of depletion of reservoir pore pressure respectively. Virgin pressures in overpressured sedimentary basins suggest that σh increases at approximately 60-80% of the rate of increase in pore pressure in the Canadian Scotian Shelf, the Australian North West Shelf and the Gannet/Guillemot Fields area of the North Sea. The total vertical stress (σv) is given by the weight of the overburden and is unaffected by changes in pore pressure. Hence, contra to simple, uncoupled models of the effect of pore pressure on rock failure, differential stress in normal fault regime basins (σv - σh) increases as pore pressure decreases, and decreases as pore pressure increases. Increased differential stress with decreased pore pressure can account for depletion-induced seismicity, despite effective stresses increasing. Decreased differential stress with increased pore pressure implies that a greater increase in pore pressure can be withstood prior to failure than would otherwise be predicted, and increases the propensity of tensile, rather than shear failure, occurring with overpressure development.

Recognition of Low Resistivity, High Permeability Reservoir Beds in the Travis Peak and Cotton Valley of East Texas : ABSTRACT

ABSTRACT Throughout East Texas, there are occurrences of unusually high-permeability beds in the Travis Peak and Cotton Valley Formations that have low resistivity even when charged with oil and gas. In most cases, these beds have retained primary porosity due to suppression of quartz cement by clay coatings that surround the grains in a conductive sheath. The clay-coated sandstones comprise a diagenetic facies that must be identified because commonly applied open hole well log analytical parameters cannot be used. The clay-coated grain facies is detectable with a cross plot of gamma ray and spontaneous potential overlain by resistivity. When gamma ray is plotted on the horizontal axis and spontaneous potential is plotted on the vertical axis, a triangular field of data points results. Data points that fall within the bounds of the triangle represent rock that has undergone normal diagenesis, is quartz cemented, and has low permeability. Data points outlying the hypotenuse represent uncemented beds with open pore throats and have high permeability. Outlying data points associated with resistivities of less than or equal to 1.5 ohm-meters are usually in the clay-coated grain facies. Zones flagged in this manner can be expected to have a cementation exponent in the range of 1.6 to 1.8, permeability in double-digit millidarcies, and be a potential low-resistivity pay.

Comparison and Verification of Electric-Log-Derived Rock Stresses and Rock Stresses Determined From the Mohr Failure Envelope

Summary This paper evaluates the correlation between values of minimum principal in-situ stress derived from sonic logs and those obtained from triaxial core tests and coefficient for earth at rest correlations. The minimum principal in-situ stress is then compared to actual field mini-frac test data, which accurately determine the minimum principal in-situ stress and are used to verify the accuracy of the correlations. The cores and the mini-frac stress test were obtained from two wells, the Gas Research Inst.'s (GRI's) Staged Field Experiment (SFE) #1 well through the Travis Peak Formation in the East Texas Basin, and the U.S. Dept. of Energy's Multiwell Experiment (MWX) wells located west-southwest of the town of Rifle, Colorado, near the Rulison gas field. Results from this study indicate that of the two approaches used in obtaining the minimum principal in-situ stress, the normalized Mohr failure envelope approach is in better agreement with the measured stress values (from mini-frac tests) in sandstone, while the sonic log approach gives closer match in shale.

Prediction of In-Situ Permeability: Significance of Rock Type Identification in Resevoir Characterization of Tight Gas Sandstones: ABSTRACT

The accurate prediction of in-situ permeability is fundamentally important in reservoir characterization. Analyses of several thousand core samples from low permeability ([open quotes]tight[close quotes]) gas sandstones of the Travis Peak, Cotton Valley and Frontier Formations reveal that the rate of permeability decrease is a function of Rock Type (interval of rock characterized by unique pore geometry). These tight gas sandstones consist of alternations of several Rock Types, depending on changes in environment of deposition and diagenesis. In such complex sequences, in-situ permeability cannot be successfully predicted using only an initial value of permeability. A knowledge of both the initial permeability (at minimum net effective stress) and pore geometry are required to predict in-situ permeability at any given value of net effective stress. Pore geometry characteristics that control in-situ permeability include size and shape aspects of both the pore throats and the pore bodies. These can be, in part, a function of mineral composition. In some instances, they are independent of composition. SEM-based pore image analysis of pore bodies and pore throats allows for the identification of different Rock Types. This information, when coupled with an initial value of permeability, allows for the prediction of permeability at any given value ofmore » net effective stress in the Travis Peak, Cotton Valley and Frontier Formations of Texas and Wyoming.« less

Measured and calculated horizontal stresses in the Travis Peak formation

Measured and calculated horizontal stresses in the Travis Peak formation

Measured and Calculated Horizontal Stresses in the Travis Peak Formation

Summary This paper presents the results of an experimental program to determine in-situ horizontal stress magnitudes from the dynamic mechanical properties of tight-gas sand cores. These measurements were made on 47 vertical plug samples from the Gas Research Inst. (GRI) test wells, Staged Field Experiment (SFE) Wells 1 through 3. The wells were cored in the Travis Peak formation of east Texas from ≈ 6,500 to ≈ 9,500 ft deep. Vertical overburden stress gradient was measured in one well using a downhole gravimeter. The core mechanical properties were used with the Anderson and Newberry equations to calculate in-situ horizontal stress. Actual in-situ minimum horizontal stress was determined from instantaneous shut-in pressures measured during minifracture and microfracture tests. The Newberry equation was found to give results that agreed best with measured horizontal stress. A closer match was obtained between measured and calculated horizontal stress values when we used dynamic Poisson's ratio from partially gas-saturated samples. The assumptions and limitations of the procedure are presented.

Resevior geometry and internal permeability distribution in fluvial, tight, gas sandstones, Travis Peak Formation, Texas : Davies, D K; Williams, B P J; Vessell, R K SPE Reservior EngngV8, N1, Feb 1993, P7–12

Resevior geometry and internal permeability distribution in fluvial, tight, gas sandstones, Travis Peak Formation, Texas : Davies, D K; Williams, B P J; Vessell, R K SPE Reservior EngngV8, N1, Feb 1993, P7–12