Travis Peak Research Articles

Analysis of a Hydraulically Fractured, Low Permeability Gas Reservoir Using Numerical Simulation

ABSTRACTWe have used a three-dimensional, multi-phase reservoir model to history match the post-fracture performance data of two separate completions in the complex, low permeability Travis Peak formation. This model consists of a two-layer, two-phase (gas-water) reservoir in communication with the wellbore via a vertical hydraulic fracture. The two-layer, two-phase reservoir model accurately matches post-fracture production data and pressure buildup test data from each Travis Peak completion interval.Our results show that the properties of the hydraulic fractures determined by this reservoir simulation are in good agreement with the fracture properties determined by a three-dimensional (3-D) fracture propagation model. In addition, reservoir simulation history matching determined that a multi-layer reservoir system was necessary to model the performance in the lower Travis Peak completion interval.

Effect of Drying on Travis Peak Cores Containing Fibrous lllite

Summary We conducted a laboratory study in the east Texas Travis Peak sandstone, which contains a small but significant amount of fibrous illite, to determine properties of preserved cores compared with those of dried and resaturated cores. Results showed that the drying process significantly changed effective water permeability, capillary pressure behavior, and electrical properties but that effective gas permeability as a function of water saturation did not change.

Reservoir Geometry and Internal Permeability Distribution in Fluvial, Tight, Gas Sandstones, Travis Peak Formation, Texas

Summary Reservoir dimensions and heterogeneities are predicted for sand bodies originating in meandering and braided fluvial channel systems. Diagenesis significantly alters original porosity and permeability characteristics in tight gas sandstones and operates within the sedimentary framework established at the time of deposition. Depositional environment therefore exercises fundamental control on reservoir dimensions and quality.

Dimensions and quality of reservoirs originating in low and high sinuosity channel systems, Lower Cretaceous Travis Peak Formation, East Texas, USA

Abstract Quantification of the dimensions and quality of fluvial reservoirs requires knowledge of channel style, depositional environment and diagenesis. Two styles of fluvial channel co-existed during the rapid aggradation of >600 m of Lower Cretaceous, Travis Peak sediments in East Texas: (1) high sinuosity (meandering) channels, and (2) low sinuosity (straight) channels. Each was restricted to a specific geographic area, the result of long-term, geomorphic stability. In both channel systems, reservoir sandstones originated principally in channel and crevasse splay environments. Reservoir models developed through sedimentological analysis are similar to those developed independently through reservoir simulation studies. Reservoir sandstones originating as point bars in high sinuosity channel systems are relatively small (1.2 km 2 or less), thin (3.6 m), heterogeneous, and isolated within non-pay mudrocks. Reservoir sandstones originating as medial and transverse/oblique bars in the low sinuosity system are areally extensive (>20 km 2 ) thick (3.6 to 13.7 m), homogeneous, and display complex pressure relationships due to avulsion of long stream segments, and the lateral and vertical stacking of successive channels in well-defined channel belts. The greatest volume of channel sandstone occurs in the low sinuosity channel system. The high sinuosity system is dominated by overbank deposits. Travis Peak sandstones have been extensively modified by compaction and cementation. Despite extensive diagenesis, permeability values reflect original depositonal environment and bedding style, even in rocks which have lost more than 80% of their original, depositional porosity. Channel sandstones have higher permeability than associated splay sandstones. Within a channel sandstone, the highest values of permeability occur in destratified, and flat- to low-angle cross-bedded sandstones: planar cross-bedded and ripple-bedded sandstones have the lowest values of permeability. Original depositional environment and bedding style exercise important control on permeability (particularly potential gas flow) even in rocks in which the pore systems have been modified significantly by diagenesis. A knowledge of depositional environment and bedding style is therefore important in predicting potential producibility in tight, gas sandstones such as the Travis Peak formation.

Travis peak core permeability and porosity relationships at reservoir stress : Luffel, D L; Howard, W E; Hunt, E R SPE Form EvalV6, N3, Sept 1991, P310–318

Travis peak core permeability and porosity relationships at reservoir stress : Luffel, D L; Howard, W E; Hunt, E R SPE Form EvalV6, N3, Sept 1991, P310–318

Evolution of Porosity and Permeability in the Lower Cretaceous Travis Peak Formation, East Texas (1)

Porosity and permeability decrease significantly with depth in low-permeability, gas-bearing Travis Peak sandstones on the western flank of the Sabine arch, east Texas. The Travis Peak Formation is approximately 2000 ft (610 m) thick and is buried to depths of 6000-10,000 ft (1830-3050 m). Reservoirs consist chiefly of sandstones of fluvial and paralic origin. Thin-section and core-analysis data from a total of 3680 ft (1122 m) of core from 26 wells indicate that both depositional environment and diagenetic history influenced the present distribution of porosity and permeability. Porosity in clean sandstones decreases from an average (geometric mean) of 16.6% at 6000 ft (1830 m) to 5.0% at 10,000 ft (3050 m). Permeability is reduced four orders of magnitude over the same depth range, from an average (geometric mean) of 10 md at 6000 ft (1830 m) to 0.001 md at 10,000 ft (3050 m). Loss of porosity by mechanical compaction took place mainly within the first 3000 ft (900 m) of burial, prior to significant cementation. The observed decline in porosity and permeability with depth between 6000 and 10,000 ft (1830 and 3050 m) results from (1) increasing quartz cement, (2) decreasing secondary porosity, and (3) increasing overburden pressure that closes narrow pore throats. At any given depth, average permeability is 10 times higher in clean fluvial than in clean paral c sandstones. Clean fluvial and paralic sandstones contain similar volumes of quartz cement, but paralic sandstones are finer grained and contain an average of 7% more total cement.

Hydraulic Fracturing Research in East Texas: Third GRI Staged Field Experiment

Summary This paper presents results from research conducted on the third Gas Research Inst. (GRI) staged field experiment (SFE) well. Research well SFE No. 3 was drilled as part of a field-based research program conducted in east Texas during the past 7 years. Most of the work before SFE No. 3 involved the Travis Peak formation; however, the Cotton Valley sandstone was the primary research target for this well. SFE No. 3 is the last in a series of research wells planned for east Texas. A fourth SFE planned for east Texas. A fourth SFE is being conducted in the Frontier formation of southwestern Wyoming. Data on SFE wells are collected from whole cores, open hole geophysical logs, in-situ stress measurements, production and pressure-transient production and pressure-transient tests, fracture stimulation treatments, fracture-diagnostic measurements, and postfracture performance tests. These data then are analyzed by research scientists, geologists, and engineers to describe the reservoir and hydraulic fracture fully. Introduction GRI has sponsored a field-based research program in east Texas during the past 7 program in east Texas during the past 7 years. A major effort of this program has been the SFE project, in which wells were drilled specifically to conduct research in the analysis and stimulation of tight gas sands and to validate technologies under development in other GRI research projects. The first two SFE wells have been completed and the results published in various reports and technical papers. The fourth SFE project, in the Frontier formation of project, in the Frontier formation of southwestern Wyoming, was completed in late 1991. This paper presents the results from the third SFE well. Data on SFE wells are collected from whole cores, openhole geophysical logs, insitu stress tests, production and pressure transient tests, fracture stimulation pressure transient tests, fracture stimulation treatments, fracture-diagnostic measurements, and postfracture performance tests. The main purpose of collecting such a comprehensive set of data is to describe the reservoir and hydraulic fracture fully. Our goal is to obtain the most accurate analysis possible to provide a better understanding of the possible to provide a better understanding of the hydraulic fracturing process. We hope that this work will lead to better treatment designs and additional gas production from tight gas sands, which we believe can be achieved through the practical application of new technologies and more rigorous analysis techniques with numerical models. Unless these models and tools can be applied on a more routine basis by the practicing engineer or geologist, however, technology transfer will not be accomplished. The development of practical and useful tools and methods that will benefit the natural gas industry is of primary importance to this research project. SFE No. 3 was drilled and completed in late 1958 and 1989. The lower Cotton Valley (Taylor) sand was the primary interval of completion and stimulation in this well. In this paper, we summarize the work performed and data collected on SFE No. 3 and performed and data collected on SFE No. 3 and present results from the data analyses. present results from the data analyses.

Strength Anisotropy in Low-Permeability Sandstone Gas Reservoir Rocks Application of the Axial Point-Load Test

ABSTRACT Axial point-load tests involve breaking specimen disks of rock with small, diametrically opposed anvils that approximate point loads. Direction of sample fracture can reflect strength anisotropy, which in otherwise homogeneous samples may correspond to the strike of natural microfractures or microfractures that exist owing to processes that reflect in situ stress directions, such as differential core expansion. In low-permeability sandstone reservoir rocks, point-load tests are potentially useful supplements to core-based studies of macrofractures and measurements of stress directions. Point-load tests on low-permeability sandstone core show marked strength anisotropy in soft Frontier Formation sandstone (Green River Basin, Wyoming) and moderate to weak anisotropy in hard Travis Peak Formation sandstone (East Texas Basin). Comparing results of 328 point-load tests with other stress-direction indicators (acoustic velocity anisotropy, anelastic strain recovery, wellbore breakouts, and hydraulically induced fractures), agreement was found between induced fracture strike and inferred maximum horizontal stress direction. The strike of induced fractures is also aligned with natural fracture directions in these rocks, however, and petrographic analysis is necessary in order to use point-load tests to infer stress directions.

Travis Peak Core Permeability and Porosity Relationships at Reservoir Stress

Summary Relationships of permeability to porosity are shown from analyses of more than 2, 100 core plugs from nine wells in the Travis Peak, a low-permeability, tight-gas sandstone formation in northeast Texas. Effects of reservoir vs. ambient stress are shown for permeability, porosity, and the Klinkenberg factor. The relationship of brine permeability to gas permeability is also shown.

Depositional, Diagenetic, and Structural Controls on Reservoir Properties of Low-Permeability Sandstone, Travis Peak Formation, East Texas

ABSTRACT The Lower Cretaceous Travis Peak Formation in East Texas is a low-permeability gas-bearing sandstone that commonly requires hydraulic fracture treatment to produce at economic rates. Stratigraphic, petrographic, and structural characterization of the Travis Peak has resulted in information that can be used by operators to evaluate and complete these reservoirs more efficiently. Depositional systems of the Travis Peak Formation in this region include braided to meandering fluvial, deltaic, and paralic systems. Reservoirs in the upper Travis Peak are tidal-channel, tidal-flat, and meandering fluvial channel sandstones, whereas reservoirs in the lower Travis Peak are braided fluvial deposits in wide channelbelts. Mudstones through out the Travis Peak are highly silty and thus do not stop vertical growth of hydraulic fractures created during well stimulation. As a result, hydraulic fractures are circular and may connect several stacked sandstones. Petrographic studies indicate that extensive quartz cement is the major cause of low permeability in Travis Peak sandstones. Because the volume of quartz cement increases with depth, matrix porosity and permeability decrease. However, natural fractures are more abundant in structurally deeper, more intensely quartz-cemented sandstones than in shallower sandstones. Mean azimuth of natural fractures is N80°E. Drilling-induced fractures and borehole breakouts indicate that maximum horizontal stress (SHmax) is oriented east-northeast, which is the direction in which hydraulic fractures will propagate. Because the hydraulic fractures propagate in a direction subparallel to the natural fractures, hydraulically induced fractures may not intersect as many natural fractures as they might if SHmax had some other orientation relative to fracture strike.

Reservoir Models for Meandering and Straight Fluvial Channels: Examples from the Travis Peak Formation, East Texas

ABSTRACT Reservoir geometry and heterogeneity are fundamentally controlled by channel style. Two channel styles existed during Travis Peak deposition: (1) meandering (high sinuosity) channels, and (2) straight (low sinuosity) channels. Each is restricted to a specific geographic area, a result of the long term stability of the loci of sediment input into the ancestral Gulf of Mexico. Reservoir models for meandering and straight fluvial systems have been developed from cores and logs using knowledge of depositional environment and channel style. Predictions of reservoir dimensions in the Travis Peak Formation are based on geologic modeling. The geologic models are supported by reservoir simulation studies performed as part of several staged field experiments sponsored by the Gas Research Institute. Reservoirs that are developed in high sinuosity systems originate as point bars and as crevasse splay deposits. They are isolated within flood basin mudrocks. Point bar reservoir sandstones average 12 ft in thickness and cover approximately 300 acres. Point bar sandstones are usually compartmentalized by mud drapes, particularly in their upper portions. The drapes are sand-rich, and do not appear to act as barriers to fluid flow when wells are fracture stimulated. Crevasse splay sandstones are laterally extensive (>640 acres) but have lower reservoir quality and are thinner than associated point bar sandstones. Reservoirs developed in the low sinuosity system originate as in-channel braid bars and as crevasse splays. Channel sandstones are lithologically homogeneous. The average thickness of a single, low sinuosity channel sandstone is 8 ft. Such deposits are rare because successive channels stack vertically. As a result of channel avulsion and vertical stacking, reservoir sand bodies are very large (at least 5000 acres) and thick (12 to 45 ft). Pressure relationships between successive channels and associated crevasse splay deposits are complex. Wells drilled in Harrison and northeast Panola counties penetrate high sinuosity channel sands while wells drilled in the rest of the study area penetrate low sinuosity channel sands. Within each area, sand bodies originating in channel and crevasse splay environments can be differentiated using a variety of wireline log responses. The volume of sand (channel sand, and channel plus overbank sand) is significantly greater in the low sinuosity system than in the high sinuosity system throughout the whole Travis Peak interval. However, the percentage of sand in the Travis Peak section increases with increasing depth in both areas. In terms of resource potential, the lower portions of the Travis Peak are extremely important because these sands are gas-saturated.

Pore Geometry in High- and Low-Permeability Sandstones, Travis Peak Formation, East Texas

Summary Petrographic and petrophysical analyses have revealed that tight sandstone possesses distinct petrological properties that differentiate it from conventional sands. Diagenetic alteration changes a wide variety of fluvial, deltaic, and marine sands into similar low-permeability rocks with nearly identical pore structures. In this paper, changes in the pore geometry and petrology as conventional sandstones become tight are examined within a single East Texas sandstone formation.

History of Quartz Cementation in the Lower Cretaceous Travis Peak Formation, East Texas

ABSTRACT Quartz is the most abundant authigenic mineral in sandstones of the Travis Peak Formation in East Texas, but the extent of quartz cementation varies widely. To determine major controls on quartz cement distribution, this study used 431 thin sections from 1,100 m of core from 26 wells. Volume of detrital clay matrix is the main textural control on quartz cement. In sandstones lacking detrital clay, no significant correlation exists between quartz cement and grain size, sorting, bed thickness, or sedimentary structure. Depositional facies was an indirect control on quartz cement distribution because facies controlled detrital matrix content, but no significant difference exists between average quartz cement volume in matrix-free paralic (16.7%) and matrix-free fluvial (17.1%) sandstones Quartz cement increases significantly with present depth from an average of 14.6% at 1,825 m to 20.0% at 3,050 m. This trend of increasing quartz cement is interpreted to be the result of 1) an early episode of quartz cementation by meteoric water that resulted in relatively uniform distribution of quartz within the formation, and 2) a later episode related to the development of stylolites that preferentially added quartz cement in the deepest sandstones. Approximately 10 to 20% of the authigenic silica in Travis Peak sandstones was derived internally from intergranular pressure solution and stylolitization; the remaining 80% was imported from unknown sources outside the sandstones.

Episodic Quartz Cementation in the Lower Cretaceous Travis Peak Formation, East Texas: ABSTRACT

Episodic Quartz Cementation in the Lower Cretaceous Travis Peak Formation, East Texas: ABSTRACT

Determination of in situ stress profiles through hydraulic fracturing measurements in two distinct geologic areas

During a hydraulic fracture treatment, the magnitudes of the minimum principal stresses ( in situ stresses) in the different layers of rock become a major factor in the growth of the fracture. The horizontal stress in the producing zone as well as the horizontal stresses in the surrounding intervals must be known in order to design and analyze a fracture treatment correctly. In order to quantify the stress profile prior to stimulation, stress tests have been performed in a total of nine wells. Seven of the wells were in the Travis Peak formation of east Texas. In these wells, 68 stress tests were performed in 61 different zones. The remaining two wells were in the Devonian Shales in the eastern U.S. A total of 13 tests were performed in these two wells. This paper presents a summary of the procedures, equipment and analyses involved in these tests. It also presents the results of all of the tests.

Improvement of Hydraulic Fracture Predictions by Real-Time History Matching on Observed Pressures

SummaryA new, fully integrated model of hydraulic fracturing can be used to compare measured and calculated pressures for parameter determination during the fracture treatment to improve the prediction of hydraulic fracture geometry. Sensor data obtained during the course of the treatment—such as wellhead flow rates, fracturing-fluid viscosity, and proppant concentration—are received directly by this model, which takes into account all the essential physical phenomena that influence the pressure response associated with hydraulic fracture growth. At any point during the treatment, the model can be rerun, faster than real time, changing reservoir and treatment parameters until the difference between calculated and measured wellhead or bottomhole pressure (BHP) histories is minimized. Updated predictions of final propped fracture geometry can then be made by running the model faster than real time, using the remaining treatment schedule as input and adopting the parameters that correspond to the best history match; these predictions may differ substantially from that of the job design, thus providing field personnel with an improved estimate of the final fracture geometry before the treatment is completed, while remedies can still be implemented.Results show history matches of the pressure response and associated fracture geometries for three treatments performed in the Travis Peak formation of east Texas and one performed on a coal seam in the Piceance Creek basin near Collbran, in western Colorado. In addition, this work is contrasted with previous efforts to deduce fracture geometry from pressure-response profiles.

Fracture Detection in Low-Permeability Reservoir Sandstone: Comparison of BHTV and FMS Logs to Core: ABSTRACT

Detection and characterization of fractures in low-permeability reservoirs is an important goal of reservoir analysis. Natural fractures may increase porosity in low-permeability rock and may enhance or limit the success of hydraulic fracture treatment. Two logging tools used for fracture detection are the borehole televiewer (BHTV), an acoustic device that maps the smoothness of the borehole wall, and Schlumberger's Formation Microscanner (FMS), a resistivity tool that produces a conductivity map of two 2.8-in. wide strips of the borehole wall. Their analysis compares BHTV and FMS logs to 1028 ft of core from three wells in the 2000-ft thick Lower Cretaceous Travis Peak Formation, a sandstone and shale unit that produces gas from low-permeability sandstone in east Texas. Core was obtained from depths of 5900 to 9900 ft. The Travis Peak provides a good test of fracture-imaging logs because natural fractures have complex geometry and variable mineral fill and because there are borehole breakouts, drilling-induced fractures, and vertical sedimentary structures that must be distinguished from natural fractures for successful fracture analysis.

Controls on Permeability Distribution in Lower Cretaceous Travis Peak Formation, East Texas: ABSTRACT

Porosity and permeability decrease significantly with depth in low-permeability, gas-bearing Travis Peak sandstones on the western flank of the Sabine uplift. The Travis Peak Formation is about 2000 ft thick and is buried to depths of 6000-10,000 ft. Thin-section and core-analysis data from 3550 ft of core from 25 wells indicate that both depositional environment and diagenetic history influenced the present permeability distribution. Reservoir sandstones are divided into two main types: fluvial sandstones deposited in a sand-rich environment and paralic sandstones deposited in mud-rich environments. Paralic sandstones are finer grained than fluvial sandstones (average of 0.12 mm vs 0.17 mm, matrix-free sandstones only) and thus probably had lower original permeability.

Paleostress directions from the preferred orientation of closed microfractures (fluid-inclusion planes) in sandstone, East Texas basin, U.S.A.

Closed extensional microfractures are useful indicators of paleostress directions in shallowly buried quartz-cemented quartz-arenites of the Lower Cretaceous Travis Peak Formation, a tabular sandstone and shale unit approximately 670 m thick that was deposited in the gradually subsiding northern Gulf of Mexico basin. The closed microfractures are syndiagenetic fluid-inclusion-rich planes that have an ENE strike that is subparallel to contemporary quartz-filled extension veins and regional normal faults, indicating that closed microfractures contain the maximum paleostress direction. These microstructures are potentially useful for mapping paleostress trajectories in passive margin and platform settings, particularly where samples are obtained from core. Previous experimental studies of microfracture closure suggest that microfractures evolved into fluid-inclusion planes by dendritic quartz precipitation. In East Texas, microfracture closure may have occurred at temperatures as low as 85°C and depths as shallow as 1500 m.

Fluvial Sandstone Reservoirs of Travis Peak (Hosston) Formation, East Texas Basin: ABSTRACT

Fluvial Sandstone Reservoirs of Travis Peak (Hosston) Formation, East Texas Basin: ABSTRACT