Travis Peak Research Articles

Subsurface fractures and their relationship to stress history in East Texas basin sandstone

Subsurface fractures were sampled with more than 400 m of core from the Lower Cretaceous Travis Peak Formation, a tabular sandstone and shale unit approximately 600 m thick that was deposited in the gradually subsiding Gulf Coast basin. Depth to the top of the formation in East Texas now ranges between 1800 and 2900 m. Fractures in sandstone exhibit features that are due to intermittent fracturing and sealing (“crack-seal”), which suggest that the fractures are the result of episodes of fluid pressure in excess of hydrostatic. Correlation of the vein-mineral precipitation sequence with the diagenetic history and the results of previous δ 18 O studies of quartz cement, indicates that fractures propagated at depths of between 900 and 1500 m during the migration of quartz-precipitating fluids. Fracture permeability provides a mechanism for the passage of large fluid volumes recorded by the precipitation of extensive quartz cement in the formation. Fractures stopped propagating before maximum burial depth was achieved. During approximately 1500 m of subsequent burial, fractures either remained partly open or were sealed by postkinematic ankerite and clay minerals.

Reliability of Laboratory Measurement of Porosity in Tight Gas Sands

Summary A study was conducted to verify or to improve the routine laboratory procedures normally used to measure porosities of cores from tight gas sands. After routine analysis of 242 core plugs from the Travis Peak formation in east Texas, 20 of the plugs were analyzed for porosity by two additional laboratories. Each of the three laboratories had problems with their results that normally would have gone unnoticed but were recognized because of disagreement with results from the other laboratories. After reruns, agreement was excellent, with a standard deviation of about 0.25 porosity units (p.u.) when comparing one laboratory against another. To improve reliability of routine porosity measurements, recommended practices and quality-control procedures are presented.

The GRI Staged Field Experiment

Summary The Gas Research Inst.'s (GRI's) Tight Gas Sands Program has been involved with research on low-permeability formations during the past 4 years. The main focus of the research has been to improve the general understanding of producing tight reservoirs, while a specific focus has been to advance the technology involving hydraulic-fracture geometry. The unique aspect of this research is that the laboratories have been actual gas wells completed in the Travis Peak formation in east Texas. To extend the development of technology fully, GRI has planned four staged field experiments (SFE's) from 1986 through 1989. The SFE program provides the opportunity to collect a wealth of data that cannot be obtained from normal cooperative research wells. The purpose of this paper is to summarize all the tests and data collected on the first SFE and to present the available results from the analyses of these data.

Cementation and burial history of a low-permeability quartzarenite, Lower Cretaceous Travis Peak Formation, East Texas

Fine-grained quartzarenites (and subar-koses) in the Lower Cretaceous Travis Peak Formation were extensively modified during burial diagenesis. Timing of diagenetic events can be constrained by combining petrographic and geochemical data with data on subsidence and thermal history. The geothermal gradient in the East Texas study area is 38 °C/km now, but it may have been as high as 44 °C/km when the Travis Peak was deposited because of elevated heat flow caused by crustal stretching associated with rifting of the Gulf of Mexico. Illite rims and dolomite were the first authigenic minerals to precipitate in Travis Peak sandstones. Dolomite probably formed soon after deposition at about 25 °C from water with a δ 18 O composition near SMOW. Next, extensive quartz cement, averaging 17% of the rock volume in well-sorted sandstones, occluded much of the primary porosity. The average δ 18 O composition of the quartz overgrowths indicates that they precipitated from meteoric fluids at temperatures of between 55 and 75 °C, at depths of 1 to 1.5 km. Dissolution of orthoclase and albitization of plagioclase followed quartz cementation and occurred prior to mid-Cretaceous movement of the Sabine Uplift. Illite, chlorite, and ankerite precipitated after feldspar diagenesis. The ankerite may have precipitated over a range of temperatures from about 80 to 125 °C, from fluids with δ 18 O composition of about +2‰ (SMOW); +2‰ is the average present composition of Travis Peak water. Most diagenesis ended when oil migrated into the Travis Peak. Later de-asphalting of the oil by solution of gas filled much of the remaining porosity with reservoir bitumen in some zones near the top of the formation.

Depositional Systems and Diagenesis of Travis Peak Tight Gas Sandstone Reservoirs, Sabine Uplift Area, Texas

Summary The Travis Peak formation (Lower Cretaceous) in the eastern East Texas basin is a fluvio-deltaic depositional system divided into large-scale facies packages: a middle sandstone-rich fluvial and delta-plain sequence that is gradationally overlain and underlain by a marine-influenced delta-fringe zone with a higher mudstone content. Domes and structural terraces on the west flank of the Sabine Uplift influenced deposition of Travis Peak sediments, and most Travis Peak gas production in this area is from thin sandstones (<25 ft [< 7.6 m] thick) in the upper delta-fringe facies. The trapping mechanism is stratigraphic pinch-out of sandstones or porosity zones within sandstones, or both, on the flanks of structures. Detailed mapping of producing sandstone sequences in the uppermost upper delta-fringe on the western flank of the Bethany structure has delineated fluvial channelways, distributary or tidal channels, and barrier or distributary-mouth bars. Most Travis Peak gas production in the Bethany West area is from the bases of channel sandstones in a marine-influenced facies belt. Travis Peak sandstones in the eastern East Texas basin have undergone a complex series of diagenetic modifications. Precipitation of authigenic quartz, ankerite, dolomite, illite, and chlorite and the introduction of reservoir bitumen were the most important causes of occlusion of primary porosity and reduction of permeability. Permeability decreases with depth in the Travis Peak, which suggests that the diagenetic processes that caused extensive cementation and resultant low permeability throughout most of the formation operated less completely on sediments deposited near the top of the succession.

Controls on Reservoir Quality in Tight Sandstones of the Travis Peak Formation, East Texas

Summary Most sandstone in the gas-bearing Travis Peak formation has undergone compaction and extensive cementation during its burial history, resulting in low porosity and permeability. Diagenetically induced permeability variations are superimposed on original permeability variations produced by depositional processes. Sandstones range from fluvial-channel to shallow-marine, bay, and tidal-flat deposits. Three types of sandstone that differ in their original permeability distribution and lateral continuity are distinguished. Travis Peak sandstones have undergone a complex series of diagenetic modifications. Precipitation of authigenic quartz, ankerite, dolomite, illite, and chlorite, and the introduction of reservoir bitumen, were the most important causes of occlusion of primary porosity and reduction of permeability. Porosimeter measured porosity is the best predictor of permeability, and there is a statistically significant inverse correlation between total volume of cement and permeability. Permeability decreases with depth in the Travis Peak, suggesting that the diagenetic processes that caused extensive cementation and resultant low permeability throughout most of the formation did not operate as completely on sediments deposited near the top of the formation.

Significance of Natural and Coring-Induced Fractures in Travis Peak Formation for Reservoir Stimulation: ABSTRACT

ABSTRACT Efficient hydraulic facture treatment of low-permeability sandstone gas reservoirs depends on an assessment of natural-fracture length, width, and abundance and on reliable predictions of the stimulation-fracture strike, which generally is parallel to the maximum horizontal stress. Analysis of 565 natural and coring-induced fractures in more than 1,800 ft of whole core from seven wells in the Lower Cretaceous Travis Peak Formation in East Texas (Fig. 1), together with borehole televiewer and other fracture-imaging logs from three wells, shows that (1) the abundance, physical properties, and orientation of natural fractures could potentially affect the success of hydraulic fracture treatment and (2) the orientation of coring-induced petal and petal-centerline fractures can be used to infer the direction of stimulation-fracture propagation. Reservoir sandstone in the Travis Peak contains subvertical natural extension fractures that are locally open in the subsurface with widths of as much as 0.2 in (5 mm) (Fig. 2) at depths of greater than 9,900 ft in hydrostatically pressured rocks. Fractures are more abundant in the hinges of gentle monoclines and in sandstone with pervasive quartz cement. Natural fractures strike east-northeast (Fig. 3), but they are not precisely parallel to the direction of stimulation-fracture propagation. During hydraulic fracture treatment, these characteristics will tend to cause fracture branching, curvature, and development of auxiliary fractures. The resulting tortuous fracture network, variable fracture widths, and potential for leakoff of treatment fluid could promote screenout and, consecquently, inefficient fracture treatment, if not considered in fracture treatment design. Figure 1. Structural setting of the study area (outlined by box) in the northern Gulf of Mexico basin. FIGURE 2. [Grey Scale] Natural extension fracture in Travis Peak Formation sandstone at 9842 ft (3000 m), S.A. Holditch & Associates SFE No. 2, Nacogdoches County, TX. Long dimension of the photograph is 4.7 in (12 cm). Figure 3. Rose diagram of natural extension-fracture attitudes in the Travis Peak Formation, East Texas. End_of_Record - Last_Page 591-------

Geology and Reservoir Characteristics of Tight Gas Sandstones in Travis Peak Formation, Chapel Hill Field, East Texas: ABSTRACT

Chapel Hill and adjacent Chapel Hill North and Northeast fields produce gas, oil, and condensate from the upper Travis Peak Formation on an anticlinal structure in Smith County, Texas. In 1985, 12.8 bcf of gas and 1.1 million bbl of liquids were recovered from gross perforated intervals mostly 100 to 200 ft thick within the 300 to 350 ft upper delta fringe facies of the formation. The Travis Peak at Chapel Hill is a quartzarenite to subarkose with abundant quartz overgrowths (15 to 20%), and minor ankerite and dolomite (< 3%) and authigenic clay minerals (< 3%). Where present, reservoir bitumen typically amounts to 5% of rock volume and occludes porosity. Porosity ranges from 2 to 17%; permeability, which ranges from < 0.001 to 99 md, averages < 0.05 md and is highly variable vertically. Hydraulic fracture treatment are required for economic production rates. The Lower Cretaceous Travis Peak in the eastern East Texas basin consists of regressive fluvial-deltaic facies overlain by marginal marine delta fringe facies. Productive upper delta fringe sandstones at Chapel Hill are interpreted as distal edges of lower delta plain to bay, tidal flat, and distributary channel deposits. Individual sandstones show highly variable thickness and mudmore » content that are reflected in gamma ray log character. The sequence is sand rich with no shale barriers to contain hydraulic fractures, and reservoir quality of sandstones is dependent, in part, on amounts of admixed silt and clay and the degree of bioturbation. Thin (4 ft), areally limited mudstones and muddy carbonates 80 ft below the top of the Travis Peak indicate local marine transgression. High sandstone percent trends show northwest to north-northwest sediment input directions consistent with regional patterns. Core and log data can be used to recognize repetitive sandstone types, but hydraulic fracturing precludes relating these types to hydrocarbon productivity.« less

Organic Geochemistry of Lower Cretaceous Travis Peak Formation, East Texas Basin: ABSTRACT

Organic Geochemistry of Lower Cretaceous Travis Peak Formation, East Texas Basin: ABSTRACT

Characterization of Crude Oil and Condensate by Time-Resolved Laser Fluorescence Microscopy--Preliminary Study: ABSTRACT

To determine the type and maturity of normal and biodegraded crude oil and condensates, 13 samples from diverse types of Tertiary and Cretaceous reservoirs from Alabama, California, Texas, and Venezuela were characterized utilizing pulsed laser fluorescence microscopy (developed by Borst for coal characterization). Parameters such as fluorescence lifetime in nanoseconds (ns) for three resolved fluorophores and percent contribution of each fluorophore were correlated with organic geochemical and bulk chemical data on crude oils and condensates. The fluorescence lifetime (ns) of the intermediate component has been correlated with ratios of aromatics to the heterocomponents (fluorescence emitters). This relationship, when compared with the ratio of aromatics to asphaltenes (fluorescence quenchers), revealed characteristic distribution of oils derived from two different reservoirs: (1) marine source-derived oil from Lovetts Creek field (Smackover), Alabama, and (2) terrestrial source-derived oil from Charamousca field (Wilcox), south Texas. These data are supported by geochemical fingerprinting. The above-mentioned ratios and the ratios of the fluorescence lifetimes of two individual fluorophores also show characteristic patterns for biodegraded (alteration in reservoir) and nonbiodegraded crude oils from the Wilcox, Duval County, south Texas, and the Oficina reservoir, Venezuela. These ratios also suggest the possible maturity of two biodegraded crude oils from the Wilcox,more » south Texas, that coincides with the results of a biomarker study. The above parameters indicate the similarity in origin of two crude oils and one condensate from the Travis Peak Formation, Chapel Hill field, east Texas.« less

Diagenesis and Burial History of Lower Cretaceous Travis Peak Sandstone, East Texas: ABSTRACT

Diagenesis and Burial History of Lower Cretaceous Travis Peak Sandstone, East Texas: ABSTRACT

Log Analysis Techniques for Quantifying the Permeability of Submillidarcy Sandstone Reservoirs

Summary A gradational diagenetic change from the "tubular" primary pore network of conventional sandstones to a pore geometry consisting of secondary-solution pores interconnected by narrow "slot-like" flow paths in low-permeability sandstones has necessitated the formulation of revised log-derived permeability equations. The equations are derived from Lower Mesaverde group core data and are tested for limitations by extrapolation to a. shallower Mesaverde interval and to a remote Travis Peak (Hosston) interval. An alternative method involving invasion inferences from a log-derived filtration index is used to complement the permeability analysis.

Petrography and Diagenesis of Lower Cretaceous Travis Peak (Hosston) Formation, East Texas: ABSTRACT

ABSTRACT The Lower Cretaceous Travis Peak (Hosston) Formation contains oil and gas reservoirs distributed from Texas to Mississippi. Much of the formation from 6,800 to 10,100 ft (2,100 to 3,100 m) in East Texas has low permeability (less than 0.1 millidarcy), but a few thin zones near the top of the formation have as much as 100 millidarcy permeability. Low permeability is caused by compaction, extensive precipitation of authigenic cements during burial, and minor pressure solution. Travis Peak sandstones in East Texas are fine- to very fine-grained quartzarenites and subarkoses having an average composition of Q95F4R1. Plagioclase feldspar is more abundant than orthoclase, and chert and low-rank metamorphic rock fragments are the most common lithic components. The first authigenic cements were clays, primarily illite, that coated detrital grains with tangentially oriented crystals. Next, extensive quartz cement (averaging 15.5 percent of the rock volume) occluded much of the primary porosity. Relatively late-stage cements include ankerite, which commonly has a dolomitic nucleus, a second generation illite, and chlorite. Ankerite and dolomite are most abundant in marginal-marine deposits near the top of the Travis Peak and less abundant in the deeper, fluvial part of the formation. Feldspar dissolution and albitization of plagioclase were also relatively late diagenetic reactions. Plagioclase composition determined by microprobe ranges from An24 to An0.1, but 83 percent of the analyses indicated a composition of less than An5. Reservoir bitumen, a solid, immobile hydrocarbon accumulation, fills pores in sandstones in the upper 300 ft (90 m) of the Travis Peak. The volume of reservoir bitumen is as much as 19 percent. The reservoir bitumen has a H/C ratio of 0.79 to 0.90, suggesting that the bitumen formed by deasphalting of oil, which caused heavy molecules to precipitate. Permeability decreases with depth below the top of the Travis Peak. Porosimeter-measured porosity is the best predictor of permeability, and there is a low but statistically significant inverse correlation between total volume of cement and permeability.

Geology of Natural Gas Reservoir: Upper Travis Peak Formation, Western Flank of Sabine Uplift, East Texas: ABSTRACT

The Travis Peak Formation (Lower Cretaceous) in the eastern East Texas basin represents a sand-rich, fluvial-deltaic depositional system. This lobate, high-constructive deltaic system prograded radially to the southeast from an Upshur County locus. Regional studies of the Travis Peak established a threefold internal stratigraphic framework: a middle sand-rich fluvial and delta-plain sequence is gradationally overlain and underlain by a marine-influenced delta-fringe zone with a higher mud content. The entire Travis Peak succession thins over the Bethany dome on the western flank of the Sabine uplift. However, the delta-fringe sequences are relatively thicker over the structure because of a disproportionately greater thinning of the middle sandy fluvial-deltaic sequence. Lesser sand deposition over the Bethany dome reflects an active structural control over facies distribution. Gas production in the Bethany field and surrounding area is concentrated in thin zones (5-15 ft) of the upper delta-fringe sequence. This distribution probably reflects the increased abundance of mudstone beds in the upper delta-fringe interval, which may have served as source rocks or barriers to upward gas migration, or as both. The predominant trapping mechanism in this region is stratigraphic sand pinch-out in a structurally updip direction on the flanks of major structures. Studies of core andmore » closely spaced electric logs west of the Bethany dome help define the depositional systems in the upper delta-fringe producing interval. This sequence comprises a complex mosaic of continental and marine facies, and exhibits an overall upward trend of increasing marine influence that spans a gradual transition into transgressive carbonates of the Sligo Formation.« less

Pore Characterization by Scanning Electron Microscope of Low-Permeability Gas Sandstones, Travis Peak Formation, East Texas: ABSTRACT

The scanning electron microscope (SEM), used in conjunction with thin-section petrography and mercury-injection analysis, is a valuable tool to evaluate authigenic cements, pore size, and pore geometry in low-permeability sandstones of the Lower Cretaceous Travis Peak Formation, east Texas. Abundant cements, which include quartz, ankerite, illite, and chlorite, are the main cause of low permeability in these quartzarenite and subarkose sandstones. In addition, reservoir bitumen occurs in zones near the top of the formation, and where abundant, it further reduces porosity and permeability. SEM and mercury-injection analysis distinguished two types of pore systems in Travis Peak samples. Matrix-rich sandstones have less authigenic cement and higher porosity and permeability than do matrix-free sandstones. Values of pore-aperture radii have a unimodal distribution, most radii being between 0.1 and 5 ..mu..m. Under SEM, the larger pores were identified as intergranular and solution pores; micropores (pore-aperture radii less than 0.5 ..mu..m) occur among detrital clay minerals. In contrast, sandstones that lack detrital clay matrix have abundant authigenic cement and reservoir bitumen, and lower values of porosity and permeability. These sandstones have a bimodal distribution of pore-aperture size, the major mode being 0.1-0.5 ..mu..m and the minor mode being less than 0.055 ..mu..m in radius.more » Most of the larger pore apertures in these samples (0.1-0.5 ..mu..m) seem to be associated with micropores in clay minerals, and solution pores, and the smallest pore apertures (less than 0.055 ..mu..m) seem to occur within the reservoir bitumen. In a sample with 18% reservoir bitumen, one-third of the total pore-aperture radii is less than 0.055 ..mu..m in diameter.« less

Depositional and Diagenetic History of Hosston Formation (Travis Peak), Nuevo Leon Group, Trawick Field, Nacogdoches County, Texas: ABSTRACT

ABSTRACT Five major lithofacies were identified in the Hosston Formation of Trawick Field, Nacogdoches County, Texas. These were identified based upon vertical changes in sedimentary structures, textures, and lithologic composition. Facies identified in the Hosston Formation included: (1) a clean, crossbedded, tidal-channel facies, (2) a sandy, bioturbated, tidal-flat facies, (3) thin, rapidly deposited, crevasse splay deposits, (4) interdistributary bay sands, silts, and muds and (5) partially reworked distal deltaic sandstones. Distinct differences are observed between the upper and lower Hosston facies due to the transition from a lower, more continental fluvio-deltaic system to an upper, marginal marine delta-fringe system. In the lower Hosston, only the channel, crevasse splay, and interdistributary bay facies are significant. The regressive nature of the formation is documented through changes in color and detrital constituents as well as in the presence of prodelta muds and shallow carbonates found exclusively in the upper Hosston. The Hosston Formation has characteristically low porosity and permeability values. Variations in the reservoir quality of Hosston sands is controlled both by environment of deposition and diagenesis. Two diagenetic pathways are postulated. In the first, extensive silica and phyllosilicate cementation dramatically reduce reservoir potential and porosity values rarely exceed 2 percent. In the second, early hydrocarbon migration inhibits additional cementation and therefore suppresses further porosity reduction. Samples following this pathway have porosities of up to 30 percent. Late stage diagenetic events include cementation by calcite and anhydrite as well as isolated occurrences of intergranular albite cementation. Channel sands of the lower Hosston maintain the highest consistent reservoir qualities.

Depositional Systems and Productive Characteristics of Major Low-Permeability Gas Sandstones in Texas: ABSTRACT

Major tight gas sandstones in Texas range from lenticular to blanket geometry, from hydropressured to geopressured, and from Pennsylvanian to Eocene in age. The Cotton Valley sandstone (East Texas basin) includes barrier- and marine-bar sandstones (blanket) derived from prograding fan deltas with associated braided stream, delta-front, and pro-delta deposits. The overlying Travis Peak Formation contains a lower deltaic facies, a middle, dominantly braided fluvial facies (broadly lenticular), and an upper transgressive clastic-to-carbonate transition. Estimated gas in place varies from 53 tcf (Cotton Valley) to 25 tcf (Travis Peak); most wells initially produce from 500 to 1,500 mcf and few wells produce 2,500 mcf. Tight gas sandstones in the Wilcox and Vicksburg Groups (G lf Coast basin) are mostly geopressured delta-front, shelf, and slope deposits. These lenticular sandstones isolated in shale have pressure gradients up to 0.81 psi/ft (18.3 kPa/m). Initial well yields are mostly 300 to 2,400 mcfd; resource estimates for tight Wilcox and Vicksburg trends are not available. Canyon Group sandstones of the Sonora basin (parts of the Ozona arch, Concho platform, and Val Verde basin) contain 24 tcf of estimated gas in place and initial flow rates are commonly 100 to 1,000 mcf. These sandstones are broadly lenticular and are interpreted to be submarine fan and possibly shelf-margin deposits. The Olmos Formation (Maverick basin) contains gas within broadly lenticular delta-front deposits of high-constructive delta systems; liquid hydrocarbons in the Olmos are trapped in more proximal facies. Gas in place in the Olmos is estimated to be 5 tcf and initial well yields are 300 to 3,000 mcf. In 1980, 893 wells were completed in formations designated as partially or completely tight by the Railroad Commission of Texas. These completions represent 2.5% of new gas wel s in the state, but 28.0% of those completed in the 5,000 to 15,000-ft depth range in that year. End_of_Article - Last_Page 476------------

Comparison of Depositional System and Reservoir Characteristics of Selected Blanket-Geometry Tight Gas Sandstones: ABSTRACT

Future development of gas in tight sandstones is highly dependent upon price and the state of technology, including detailed understanding of internal and external reservoir geometry. Part of the tight gas resource lies in blanket-geometry, siliciclastic sandstones; over 30 such sandstones in 16 sedimentary basins and at depths mostly less than 10,000 ft (3,000 m) were reviewed for the Gas Research Institute. Emphasis was placed on depositional systems and resulting lithogenetic facies as an important control on sand body geometry. In contrast to lenticular sandstones, blanket-geometry tight gas sandstones were deposited as deltaic, barrier strand plain, and shelf systems. Overlap occurs between systems, as in the case of a strand plain developed marginal to a deltaic depocenter. Not all parts of all sandstones are tight (< 0.1 md permeability); tight areas vary from extensive (J Sandstone, Denver basin) to very limited (Hartselle Sandstone, Black Warrior basin). Five stratigraphic units were selected from which developments in reservoir characterization, fracture treatment, and other technologies can likely be extrapolated to a wider group of tight gas reservoirs. The Travis Peak Formation (East Texas basin/North Louisiana salt basin) is a fan delta system. It ranges in depth from 3,000 to 11,000 ft (900 to 3,350 m), with net pay of 30 to 86 ft (9 to 26 m) and post-stimulation gas flows of 500 to 1,500 MCFGD. The Frontier Formation (Greater Green River basin) is a wave-dominated End_Page 460------------------------------ deltaic system with associated barrier strand plain facies; shallower prospective areas range in depth from 7,000 to 12,000 ft (2,100 to 3,650 m). The Frontier has net pay of 10 to 90 ft (3 to 27 m) and post-stimulation gas flows up to 2,500 MCFGD. Characteristics of the Travis Peak have extrapolation potential to Tuscarora-Medina-Clinton sandstones of the Appalachian basin; deltaic facies of the Frontier may correspond to parts of the Davis Sandstone (Fort Worth basin), Olmos Formation (Maverick basin), and the Fox Hills Sandstone (eastern Greater Green River basin). Cozzette and Corcoran Sandstones (Piceance Creek basin) are predominantly barrier strand plain deposits; they range in depth from 2,500 to 8,000 ft (760 to 2,400 m), with net pay of 10 to 70 ft (3 to 21 m) each and pos -stimulation gas flows average 1,250 MCFGD. The upper Almond Formation (eastern Greater Green River basin) may contain more shallow marine and offshore bar than barrier strand plain facies. It occurs at depths of 6,000 to 15,000 ft (1,800 to 4,600 m), with net pay of 14 to 18 ft (4 to 5.5 m); and post-stimulation gas flows up to 1,700 MCFGD. The characteristics of the Cozzette, Corcoran, and upper Almond may be extrapolated to other marginal marine units in the Mesaverde Group and parts of the Dakota Sandstone in several Rocky Mountain basins. Shelf deposits include the Mancos B interval of the Mancos Shale (Piceance Creek and Uinta basins) at depths of 3,500 to 5,000 ft (1,000 to 1,500 m) in areas of recent drilling. Mancos B net pay ranges from 38 to 120 ft (11.5 to 36.5 m), and po t-stimulation gas flows range up to 350 to 1,200 and MCFGD. Extrapolation potential exists in the Anadarko basin and Northern Great Plains area. These five stratigraphic units have potential for increased commercialization. By understanding the initial properties derived from the depositional setting of a tight gas sand, the explorationist can better extrapolate successful exploration, stimulation, and production techniques between reservoirs in similar depositional settings. End_of_Article - Last_Page 461------------

Outcrop-to-Basin Stratigraphy and Structure of Glen Rose Limestone of Central Texas: ABSTRACT

The Glen Rose Limestone is a proven oil and gas producer in south Texas along the Stuart City reef trend. However, it has not been productive, except in minor occurrences, in the East Texas basin, even though it is present in an area of approximately 75,000 mi2 (195,00 km2) and attains a maximum thickness of 3,500 ft (1,067 m). This absence of production is believed to result from a lack of exploration rather than a lack of potential. Therefore, a regional study of the outcrop-to-basin stratigraphy and structure of the Glen Rose in central Texas was undertaken to correlate existing stratigraphic nomenclature and to determine the depositional and diagenetic history. Be relating these to known production, it should be possible to identify potential exp oration fairways. Cross sections were used in establishing stratigraphic correlations, resulting in a division of the Trinity Group different from that commonly seen in literature. The group is divided into the Glen Rose and Travis Peak subgroups, with the division at the outcrop placed at the Hensel-lower Glen Rose contact. However, in the basin, the Pearsall-Rodessa contact is used as it is time-equivalent to the division adopted at the outcrop. Examination of cores, cuttings, and sample logs defined the depositional and diagenetic environments of Glen Rose strata. Isopach maps and seismic sections were used to map distribution of facies tracts related to production. Facies and structure of known production areas were compared to those of untested areas to define possible exploration fairways and to map recommended exploration trends. Principal of these is the Stuart City reef trend. End_of_Article - Last_Page 548------------

Stratigraphic Distribution of Hydrocarbons with Differing API Gravities in East Texas Basin: ABSTRACT

In studying the stratigraphic and geographic distributions of oils initially produced from seven East Texas Cretaceous formations, the effects of depth, temperature, and rate of burial on increasing hydrocarbon maturation, expressed as increasing API gravity, can be determined statistically. Analysis of both linear-regression and data-density trends indicates that API gravity increases as the oil matures during burial. Linear-regression analyses yield positive API-gravity gradients and low correlation coefficients for the data populations. Data-density trends show well-delineated and differing API-gravity gradients with ordinal and abscissal limits. From younger to older formations, there are two main trends of increasing API gravity. The oil from sub-Clarksville reservoirs, showing the best-delineated high API-gravity gradient, represents one main trend. The oils from Woodbine and Paluxy reservoirs show both main trends; API gravity increases rapidly, then slowly, as burial continues. The oils from Glen Rose, Rodessa, Pettet, and Travis Peak reservoirs show the second main trend, that is, a low API-gravity gradient. A composite plot for the seven formations, showing one curvilinear trend, with both high and low API-gravity gradients, implies different radiocarbon maturation rates tor the East Texas oils. Almost all maturation trends are within a temperature range of 110 to 250°F (43 to 121°C), which falls below the the retical temperature window of 250 to 350°F (121 to 177°C) for maximum hydrocarbon generation. For each formation, the geographic distributions of API gravity, depth of burial, and formation temperature establish a stratigraphic, geographic, and tectonic framework for studying the statistical distributions. Generally, high API gravity oils have been produced from the deep southern and shallow eastern parts of the basin. Lower API gravity oils are produced from the northern and western shallow parts of the basin. End_of_Article - Last_Page 1428------------