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Analysis of Natural Fractures and Borehole Ellipticity Travis Peak Formation East Texas
(1987) Laubach, Stephen E. (Stephen Ernest), 1955-; Baumgardner, Jr., Robert W.; Meador, K. J.
This report summarizes petrographic studies of natural and coring-induced fractures in 7 cores from the Travis Peak Formation, a low-permeability gas sandstone in East Texas, and also presents an analysis of fracturing and wellbore elongation based on Borehole Televiewer, Formation Microscanner, and Ellipticity logs from 12 Travis Peak wells. Natural, vertical extension fractures in sandstone are open or only partly mineral-filled in the cored depth range (approximately -5,000 to -10,000 ft), and they are therefore potential gas reservoirs as well as a potentially important influence on commercial hydraulic fracture treatment. Crack-seal structure in fracture-filling quartz shows that fracturing and quartz cementation were contemporary; this result, together with evidence of timing of fracturing and the large water volumes that are inferred to have passed through the Travis Peak, suggests that natural hydraulic fracturing influenced fracture development. Healed transgranular microfractures that occur in sandstone can be used to ascertain natural fracture trends in core that lacks macrofractures, and coring-induced petal-centerline fractures can be used to infer stress orientations. Fractures trend ENE to E. In the upper Travis Peak, borehole ellipticity trends ENE, parallel to fracture trends, and in the lower Travis Peak ellipticity trends NNW, parallel to the direction of least horizontal stress.
Application of Advanced Reservoir Characterization Simulation and Production Optimization Strategies to Maximize Recovery in Slope and Basin Clastic Reservoirs, West Texas (Delaware Basin)
(1997) Dutton, Shirley P.; Asquith, George B.; Barton, Mark D.
The objective of this Class III project is to demonstrate that detailed reservoir characterization of elastic reservoirs in basinal sandstones of the Delaware Mountain Group in the Delaware Basin of West Texas and New Mexico is a cost-effective way to recover more of the original oil in place by strategic infill-well placement and geologically based field development. The study focused on Geraldine Ford field, which produces from the upper Bell Canyon Formation (Ramsey sandstone), and West Ford field, which produces from the upper Cherry Canyon and lower Bell Canyon Formations. Reservoirs in these and other Delaware Mountain Group fields have low producibility (average recovery <14 percent of the original oil in place) because of a high degree of vertical and lateral heterogeneity caused by depositional processes and post-depositional diagenetic modification. Outcrop analogs were studied to better interpret the depositional processes that formed the reservoirs at Geraldine Ford and West Ford fields and to determine the dimensions of reservoir sandstone bodies. Stratigraphic relationships examined in laterally continuous outcrop exposures of upper Bell Canyon sandstones in Culberson County, Texas, indicate that the sandstones were deposited by high- and low-density turbidity currents in a basinal deep-water setting. The fundamental depositional element is the channel with attached levees and lobes. These elements appear to initially step into the basin, aggrade, then step back toward the shelf.
Application of Advanced Technologies in Tight Gas Sandstones - Travis Peak and Cotton Valley Formation, Waskom Field, Harrison County, Texas Reservoirs
(1991) CER Corporation; Bureau of Economic Geology
Staged Field Experiment No. 3: Application of Advanced Technologies in Tight Gas Sandstones - Travis Peak and Cotton Valley Formations, Waskom Field, Harrison County, Texas The Gas Research Institute has sponsored research directed towards improving the recovery efficiency and reducing the cost of producing gas from tight reservoirs. To more effectively acquire data and perform research experiments, the concept of Staged Field Experiments (SFEs) was developed. SFE No. 3 is the third well in a series of four SFEs. The well is located in the Waskom Field in Harrison County, Texas. Engineering and geologic data were measured and analyzed on the Travis Peak and Cotton Valley Formations. SFE No. 3 provided a field laboratory site to test technology on in-situ stress profiling, fracture diagnostics, real-time fracture analysis, and pre- and post-fracture well performance analysis. This report documents the detailed information and results from GRI's research efforts in SFE No. 3.
Application of Borehole-Imaging Logs to Geologic Analysis, Cotton Valley Group and Travis Peak Formation, GRI Staged Field Experiement Wells, East Texas
(1990) Laubach, Stephen E. (Stephen Ernest), 1955-; Hamlin, H. Scott; Buehring, Robert; Baumgardner, Jr., Robert W.; Monson, Eric R.
This report summarizes studies of two geophysical logging tools, the borehole televiewer and the Formation Microscanner, that were used in GRI's three Staged Field Experiment wells and in a cooperative well in East Texas. These tools can detect natural fractures and induced fractures that reflect in situ stress conditions, as well as lithologic features that can be important for geologic interpretation. Improvement in borehole televiewer and Formation Microscanner technology has been rapid in the past several years, but calibration of the logs with core is needed to ensure accurate interpretations of the logs. Our study compares borehole televiewer and Formation Microscanner logs with core from wells in low-permeability gas reservoir sandstone. Vertical fractures in Travis Peak and Cotton Valley sandstone usually are visible on borehole televiewer and Formation Microscanner logs, but some fractures were missed or are indistinct. Aspects of fracture shape can be determined, and fractures can generally be separated from borehole breakouts, but natural fractures are difficult to distinguish from some types of drilling-induced fractures on either log. Fracture orientation is readily obtained for inclined fractures from either borehole televiewer or Formation Microscanner logs, but the orientation of vertical fractures, the common fracture type in East Texas reservoirs, can be ambiguous locally on both logs. Formation Microscanner images can be used to help document and interpret depositional environment, and they provide images of sedimentary structures and thin beds.
Characterization of Facies and Permeability Patterns in Carbonate Reservoirs Based in Outcrop Analogs
(1992) Kerans, C. (Charles), 1954-; Lucia, F. Jerry; Senger, Rainer K.; Fogg, Graham E.; Nance, Hardie Seay, 1948-; Hovorka, Susan D.
More than 13 billion barrels (Bbbl) of mobile oil and 17 Bbbl of residual oil will remain in San Andres and Grayburg reservoirs at abandonment under current development practices. Through the development and application of new recovery technology, a large part of this resource can be recovered. This report focuses on research for the development and testing of new techniques for improving the recovery of this resource. Outcrop and subsurface geologic and engineering data are utilized to develop new methodologies through the integration of geologic observations and engineering data for improving numerical models that predict reservoir performance more accurately. Extensive regional mapping of the 14-mile by 1,200-foot San Andres outcrop, located on the Algerita Escarpment, Guadalupe Mountains, New Mexico, demonstrates that the San Andres carbonate-ramp complex is composed of multiple depositional sequences that have significant basinward shifts in reservoir-quality facies tracts occurring across sequence boundaries. Detailed geologic and petrophysical mapping of three reservoir-quality facies tracts demonstrates that the fundamental scale of geologic description for reservoir characterization is the parasequence and its component rock-fabric-based facies. Descriptions of cores from the Seminole San Andres Unit illustrate that the parasequence is also the fundamental geologic scale for reservoir mapping in the subsurface.
Characterization of Facies and Permeability Patterns in Carbonate Reservoirs Based on Outcrop Analogs
(1993) Kerans, C. (Charles), 1954-; Lucia, F. Jerry; Senger, Rainer K.
More than 13 billion barrels (Bbbl) of mobile oil and 17 Bbbl of residual oil will remain in the San Andres and Grayburg reservoir at abandonment under current development practices. Through the development and application of new recovery technology, a large part of this resource can be recovered. This report focuses on research for the development and testing of new techniques for improving recovery of this resource. Outcrop and subsurface geologic and engineering data are utilized to develop new methodologies through the integration of geologic observations and engineering data for improving numerical models that predict reservoir performance more accurately. Extensive regional mapping of the 14-mile by 1,200-foot San Andres outcrop, located on the Algerita Escarpment, Guadalupe Mountains, New Mexico, demonstrates that the San Andres carbonate-ramp complex is composed of multiple depositional sequences that have significant basinward shifts in reservoir-quality facies tracts occurring across sequence boundaries. Detailed geologic and petrophysical mapping of three reservoir-quality facies tracts demonstrates that the fundamental scale of geologic description for reservoir characterization is the parasequence and its component rock-fabric-based facies. Descriptions of cores from the Seminole San Andres Unit illustrate that the parasequence is also the fundamental geologic scale for reservoir mapping in the subsurface.
Characterization of Lower Eocene Reservoirs in the LL-652 Area, Lagunillas Field - Draft Report
(1994) Tyler, N.; Ambrose, William A.; Dutton, Shirley P.
Lower Eocene reservoirs (C Members) in the LL-652 area will contain substantial volumes of remaining mobile oil (923 million barrels [MMbbl]) after primary development. This resource exists in poorly drained or undrained reservoir compartments defined by a combination of complex structure and the heterogeneous tide-dominated deltaic facies geometry. The product of this combined structural and depositional complexity are reservoirs that have a high degree of geologic heterogeneity, considerable variation in reservoir quality, and therefore a low recovery efficiency. The tide-dominated deltaic depositional model of the C Members in the LL-652 area captures a system of dip-elongate distributary-channel sandstones that merge northeastward with extensive, dip-parallel delta-front sandstones. These two facies compose most of the reservoir sandstones and therefore contain most of the remaining oil. Permeability range and average are similar for the major facies. However, there are significant permeability contrasts (up to three orders of magnitude) locally between distributary-channel and tidal-flat, fluvial-estuarine channel and distal delta-front, and distributary-channel and delta-front facies where the base of the distributary-channel facies contains clay clasts that may retard vertical fluid flow. Diagenesis, not depositional environment, is the main control on porosity and permeability distribution in the C Members. Porosity and permeability in the C Members decrease with increasing depth. In particular, the volume of quartz cement is the main influence on reservoir quality, and because the volume of quartz cement increases significantly with depth, reservoir quality decreases with depth. The original-oil-in-place (OOIP) resource base of the C Members in the LL-652 area has been increased by 867 MMbbl (60 percent) to 2,318.2 MMbbl. This increase is mainly in the C-3-X and C-4-X Members through documenting additional reservoir area and through improved quantification of petrophysical parameters such as porosity. Extended development through continued pattern infill with 97 new wells will increase reserves from 127 MMbbl to 302 MMbbl. However, an additional 116 MMbbl can be produced from 102 geologically based infill wells strategically targeted to tap areas of high remaining oil saturation by contacting narrow sandbodies that pinch out over distances less than the current 80-acre (1,968 ft [600 m]) well spacing. A pilot waterflood in the Upper C-4-X Submember in the eastern part of the LL-652 area can recover an additional 70 MMbbl of oil. Expansion of waterflood operations to the entire field could increase recovery by as much as 20 percent of the OOIP, representing a secondary recovery resource of approximately 460 MMbbl. The LL-652 area is divided into five main and two minor structural compartments. The central structural compartment is the largest production area in the field and includes 76 wells with a cumulative production of 85.8 MMbbl. Seventy-seven percent (66.1 MMbbl) of this production comes from the C-4-X.01 reservoir.
Characterization of Lower Eocene Reservoirs in the LL-652 Area, Lagunillas Field - Final Report
(1994) Tyler, N.; Ambrose, William A.; Dutton, Shirley P.
Lower Eocene reservoirs (C members) in the LL-652 area will contain substantial volumes of remaining oil (923 million barrels [MMbbl]) after primary development. This resource exists in poorly drained or undrained reservoir compartments defined by a combination of complex structure and heterogeneous tide-dominated deltaic facies geometry. The product of this combined structural and depositional complexity is reservoirs that have a high degree of geologic heterogeneity, considerable variation in reservoir quality, and, therefore, a low recovery efficiency. The tide-dominated deltaic depositional model of the C members in the LL-652 area captures a system of dip-elongate, distributary-channel sandstones that merge northeastward with extensive, dip-parallel delta-front sandstones. These two facies compose most of the reservoir sandstones and therefore contain most of the remaining oil. Permeability range and average are similar for the major facies. However, there are significant permeability contrasts (up to three orders of magnitude) locally between distributary-channel and tidal-flat, fluvial-estuarine channel and distal delta-front, and distributary-channel and delta-front facies where clay clasts at the base of the distributary-channel facies may retard vertical fluid flow.
Characterization of Reservoir Heterogenity in Carbonate-Ramp Systems, San Andres/Grayburg Permian Basin
(1991) Kerans, C. (Charles), 1954-; Lucia, F. Jerry; Senger, Rainer K.; Fogg, Graham E.; Nance, Hardie Seay, 1948-; Kasap, Ekrem; Hovorka, Susan D.
This report summarizes research carried out by the Bureau of Economic Geology's San Andres/Grayburg Reservoir Characterization Research Laboratory (RCRL) from September 1988 through September 1990. The goal of the RCRL program was to develop advanced approaches to reservoir characterization for improved recovery of the substantial remaining mobile oil in San Andres and Grayburg reservoirs. Emphasis was placed on developing an outcrop analog for San Andres strata that could be used as (1) a guide to interpreting the regional and local geologic framework of the subsurface reservoirs and (2) a data source illustrating the scales and patterns of variability of rock-fabric facies and petrophysical properties, particularly in lateral dimensions, and on scales that cannot be studied during subsurface reservoir characterization. Areas selected for study were the San Andres exposures of the Algerita Escarpment in the northern Guadalupe Mountains and the Seminole San Andres Unit on the northern margin of the Central Basin Platform. The outcrop-analog research was emphasized because it had received little attention before this study by either industry or academe. Reports in this summary involve (1) outcrop and subsurface geological characterization of the Algerita Escarpment San Andres and the Seminole San Andres Unit (Kerans), (2) correlation of detailed outcrop mapping in order to research cored wells at Lawyer Canyon, Algerita Escarpment (Nance), (3) diagenetic/petrographic analysis of selected upper San Andres facies focusing on the origin of moldic porosity (Hovorka), (4) geologic engineering description of the upper San Andres carbonates at Lawyer Canyon and the upper producing interval at Seminole (Lucia), (5) geostatistical analysis of permeability patterns and stochastic-based finite-difference modeling of the upper San Andres parasequence window (Senger and Fogg), and (6) deterministic finite element modeling of the upper San Andres parasequence window (Kasap). Availability of basic data for these studies is summarized in the appendix.
Characterization of the Grayburg Reservoir of the Mobil University unit 15/16 in Dune Field, Crane County, Texas
(1985) Bebout, Don G.; Leary, D. A.; Lucia, F. Jerry
A project was initiated by the Bureau of Economic Geology in 1981 to investigate the distribution and nature of oil production in Texas. Approximately 500 reservoirs having a cumulative production of more than 10 million barrels of oil each were included in this study; these reservoirs have produced more than 71 percent of the total Texas production. These larger reservoirs were grouped into 47 plays based on the original depositional setting of the rocks and source and on reservoir and trap characteristics. Twenty-seven of these plays located in the Paleozoic basins of North and West Texas account for 73 percent of the total in-place oil in the state. Most of the Paleozoic production is from dolomite reservoirs. Results of this initial reservoir characterization project by the Bureau are summarized in the "Atlas of Major Texas Oil Reservoirs" (Galloway et al., 1983). Reservoirs producing from the San Andres/Grayburg Formations were selected for study because of their high cumulative production and low recovery efficiencies (30 percent average). For example, in Texas, 51 percent (80 billion barrels) of the original oil in place and 43 percent (46 billion barrels) of the cumulative production are from the Permian Basin (Figs. 1 and 2). Within the Permian Basin, 83 percent (16.6 billion barrels) of the cumulative production is from carbonates (Fig. 3), and 46 percent (7.7 billion barrels) of this is from San Andres/Grayburg reservoirs (Fig. 4). Therefore, San Andres/Grayburg reservoirs are major contributors to Texas oil production (17 percent of the total cumulative production of Texas) (Fig. 5). Better geological definition of reservoirs incorporated into engineering models and studies should lead to more efficient development of secondary and tertiary recovery methods.
Chararcterization of Heterogeneity Style and Permeability Structure in Fluvial Reservoirs
(1995) Barton, Mark D.; Angle, Edward S.; Yeh, Joseph S.
The Cretaceous Acu Formation was investigated as an analog to a heterogeneous group of reservoirs having significant potential for reserve growth in the Potiguar Basin of Brazil. Architectural, lithologic, and petrophysical information was collected from an outcrop exposing a fluvially deposited sandstone body located in the state of Rio Grande do Norte, Brazil. Sedimentologic descriptions of the sandstone body were collected from a series of vertical transects spaced evenly across the outcrop. Stratal surfaces traced between transects were recorded on photomosaics. Measurements of permeability were obtained from each transect by use of a portable probe-style mechanical field permeameter. A cross-section depicting bedding architecture, sedimentologic attributes, and permeability values was constructed, and the information incorporated into a two-dimensional representation of reservoir architecture using Stratamodel's Stratigraphic Geocellular Modeling software (SGM). The SGM technique deterministically interpolates permeability data between transect locations using a lithologic or stratigraphic framework.
Comparative Anatomy and Petrophysical Property Structure of Seaward- and Landward- Stepping Deltaic Reservoir Analogs, Ferron Sandstone, Utah
(1995) Barton, Mark D.; Angle, Edward S.
The recovery of natural gas from fluvial-deltaic reservoirs is governed by complex internal architectures. To aid in the translation of outcrop geology to reservoir equivalents, all existing Ferron outcrop, petrophysical, and subsurface data have been integrated into a geologic model of reservoir heterogeneity that compares and contrasts seaward- and landward-stepping stratigraphic cycles. Reservoir architecture varies in a predictable fashion between seaward- and landward-stepping stratigraphic cycles. Within seaward-stepping units, delta-front strata are highly compartmentalized by marine and marginal marine shales coincident with stratigraphic cycle, parasequence, and mouth-bar bounding surfaces. Coeval distributaries are volumetrically a minor component and are preserved as ribbon-like sand bodies encased in finer-grained strata. By contrast, within landward-stepping units, parasequences and component mouth-bar deposits are amalgamated into a lithologically homogeneous strike-elongate sand body. Coeval distributaries are volumetrically a major component and are preserved as a complex network of interconnected, lithologically diverse sand bodies. Internal heterogeneities, related to floodplain, abandoned channel fill, and mud-clast lag deposits, severely disrupt lateral and vertical continuity. Analysis of the Ferron gas field reveals that favorable sites for stratigraphic entrapment occur where proximal and distal portions of parasequences pinch out into lagoonal and marine mudstones, respectively.
Comparative Engineering Field Studies and Gas Resources of the Travis Peak Formation, East Texas Basin
(1986) Lin, Zsay-Shing; Finley, Robert J.
Data from eight fields producing from the Travis Peak Formation in the eastern East Texas Basin were used to define key engineering parameters for each field and to develop resource-reserve estimates. Field-average porosities range from 8 to 11 percent, and the median permeability for 191 wells is 0.088 md; field-average permeability ranges from 0.006 to 0.1 md. Gas productivity generally increases from south to north across the area studied with changes in the reservoir drive mechanism. Gas in place in the Travis Peak of the East Texas Basin is estimated to be 19.5 Tcf, assuming 12 percent of the area of the basin is ultimately productive.
Contributions from the Chemical Laboratory
(University of Texas at Austin, 1887) Everhart, Edgar
Contributions from the Chemical Laboratory.
(University of Texas at Austin, 1893) Everhart, Edgar
Contributions to Geology, 1928
(University of Texas at Austin, 1928-01-01) University of Texas at Austin
Coordination of Geological and Engineering Research in Support of Gulf Coast Co-Production Program
(1985) Finley, Robert J.; Morton, Robert A.
The objective of this investigation was to evaluate the mechanism of secondary gas recovery by co-production in a slightly geopressured watered-out reservoir (Hitchcock N.E. field). This involved making a geological interpretation of the field and defining the reservoir parameters for reservoir engineering and modeling analysis. The excellent reservoir parameters of the Frio 1A1 sandstone are due to its distributary-mouthbar origin. Slight salinity reductions during production may be evidence of contemporaneous shale dewatering. Geochemical data indicate that the hydrocarbons had a deep source and were introduced by very saline brines. Numerical simulation of the Hitchcock N.E. field is being carried out by modeling the physical dimensions of the field, determining reservoir properties, and matching simulated pressures with historical measures. The historical and simulated measures match has not yet been achieved satisfactorily. Hence, no attempt was made to simulate the future performance of the Hitchcock N.E. field. Studies at the Delee No. 1 well show that there are large short-term variations in mud and mud filtrate resistivity while a well is being drilled. Boron concentrations in the Frio 1A1 sandstone are high and must be corrected for when interpreting some types of neutron logs.
Coordination of Geological and Engineering Research in Support of Gulf Coast Co-Production Program
(1986) Light, M. P. R.; Jackson, M. P. A.; Ayers, Jr., W. B.
More than 150 gas fields were reviewed, and 25 fields were selected using modified specific selection criteria as outlined by Gregory and others (1983). Further evaluation of these fields is necessary to obtain a new ranking for Gregory's class A, B, and C divisions. A list of the 25 most favorable fields was sent to Eaton Operating Co., who were to approach likely companies to initiate joint ventures in co-production. Four reservoirs containing dispersed gas were examined for their co-production potential. Reservoirs in Port Acres and Ellis fields produce from the Hackberry Member of the Oligocene Frio Formation, and two reservoirs in Esther field produce from the lower Miocene Planulina Zone. Log-pattern and lithofacies maps, together with stratigraphic position, suggest that the reservoirs are in ancient submarine-fan deposits. Dip-elongate, channel-fill sands are characteristic; reservoir sands pinch out along strike. Growth faults, common in the submarine slope setting, form updip and downdip boundaries, producing combination traps. In Ellis field, co-production accounts for 300 Mcf (8.5 x 106 m3) of gas per day. Port Acres field contains the largest remaining reserves, but other technical and economic factors limit co-production there. Recent drilling has extended primary production and delayed co-production in Esther field. The Gas Research Institute requested that further work on the selection and evaluation of potential co-production gas fields be terminated because funds were required for the Port Arthur project.
Coordination of Geological and Engineering Research in Support of the Gulf Coast Co-Production Program
(1987) Tyler, N.; Light, M. P. R.; Ambrose, William A.
Complex and heterogeneous Hackberry reservoirs at Port Arthur field were deposited in a submarine canyon/fan setting. Conventional fieldwide hydrocarbon recovery efficiencies are low, but the potential for secondary gas recovery is high. Free gas remains trapped in uncontacted and untapped compartments at reservoir abandonment. The total fieldwide resource amounts to 13.9 Bcf. The probable and possible resource for a single infill well is 6.5 Bcf in four separate stringers. Three optimum brine-disposal sands and the best brine-disposal site were selected in Northeast Hitchcock field based on sand-body complexity, thickness, depth, and brine-disposal capacity. The equilibrium distribution of inorganic species in different combinations in the produced waters at surface and formation temperatures and pH was estimated from chemical analyses. SOLMNEQ computations suggest carbonate scaling may occur in surface equipment of Miocene disposal sandstones unless inhibitors are used. At Northeast Hitchcock field, well-winnowed sandstones of shallow-marine origin compose the major reservoir sands and act as preferential conduits for fluid migration. Dislodged, abundant authigenic kaolinite in these sands can plug pores during production, suggesting a maximum rate of production will need to be determined to avoid reservoir damage.
Coordination of Geological and Engineering Research in Support of the Gulf Coast Co-Production Program
(1989) Jirik, Lee A.; Ambrose, William A.; Kerr, D. R.; Light, M. P. R.
Shallow-marine sandstones in Northeast Hitchcock field having high porosities and permeabilities contain abundant authigenic kaolinite and have acted as preferential conduits for fluid migration. Authigenic clay creates fluid production problems because of its delicate structure. Dislodged clay will obstruct pore throats at high production rates. A maximum safe rate of fluid production will need to be determined for co-produced wells. Middle and lower Miocene barrier-island sands in Northeast Hitchcock field have the potential for receiving large volumes of co-produced brines. These sands have permeabilities in excess of 2,000 md, are internally homogeneous, and are laterally extensive in the field area. Detailed geologic analyses of two reservoirs in Seeligson field delineate heterogeneous, fluvial sandstones that probably contain isolated, undrained reservoir compartments. Zone 15 can be subdivided into at least four genetic sandstones, and Zone 18-C can be subdivided into two separate sandstones. Two new pool discoveries (Miocene) in Tom O'Connor field developed during growth-fault activity along the Vicksburg Fault Zone. Deposition of these sandstones, as part of an offshore system during initial parasequence deposition, was confined between the Vicksburg Fault Zone and the Tom O'Connor anticlinal crest.