ABSTRACT Overpressured Yegua gas-condensate reservoirs in central Wharton County occur within four cycles of sand deposition which are found far downdip of the major Yegua sand depocenters. Gas- condensate fields are found where these sandstones were deposited within at least two distinct Yegua expansion-fault systems, possibly near or beyond the most seaward Wilcox shelf edge. Four sand-bearing intervals are present within sequences designated as 10 through 70. The '60' sandstones of the lower Yegua Formation (Anomalina umbonatus zone) lie downdip of a pronounced flexure, are associated with middle to outer neritic fauna, and represent a complex of channeled turbidite deposits on the outer shelf or upper slope. The '60' interval was deposited before movement on most Yegua faults. The sandstones are productive at Phase Four and Gresham fields. An upper lower Yegua sand-bearing interval ('50') has not produced in the downdip fault trend, but is the main (Cook Mountain) reservoir interval in 'mid-dip' fields. The '40' sandstones at the base of the upper Yegua Formation form a small but thick gas-productive birdsfoot delta in the Phase Four field area fed by channels which expand across several faults. The '30' sandstones (Eponides yeguaensis zone) occur primarily as thick strike-elongate sand bodies, interpreted to represent a barrier-bar complex. This sandstone sequence thickens markedly, from 200 ft to over 800 ft, over a fault of the Phase Four system at Gresham field. The sandstones produce at Menefee, Black Owl, and Gresham fields. The '20' sand stones (Discorbis yeguaensis zone) occur downthrown to the Fault within the domino-style glide-fault system in central Wharton County. They represent proximal to distal delta-front deposits of the Shanghai Delta System, inferred to be fed by a channel. The sandstones are productive at Shanghai, East, and the El Campo field complex. The upper Yegua intervals carry beach to middle neritic faunas, and represent mostly shallow-water high-energy deposition. The '20,' '30,' and '40' sandstone intervals may represent drops in relative sea level in the area. Gas has been trapped in rollover anticlines downthrown to expansion faults of both the Phase Four and fault trends, downthrown closures against sealing faults, upthrown closures, and stratigraphic traps. Most reservoirs are small in area (200 to 400 acres) but prolific (1100 to 2100 MCF/ac-ft), although traps of several thousand acres are present in the El Campo complex. Stratigraphic complexities which form reservoir boundaries include channel boundaries and unconformities related to sandstone deposition. Structural complexities include antithetic faults, closely-spaced expansion faults, and horsetail faults which die out upward into sand sequences. Seismic signatures of gas-bearing Yegua sandstones are of three classes: 1) strong fluid-contact reflectors with AVO anomalies from thick sandstones, as at Black Owl and fields; 2) strong bedding-parallel reflectors with AVO anomalies, derived from thinner gas-filled sandstones, as at Phase Four; and 3) little reflection character from gas-filled, highly laminated sequences, as at El Campo. AVO anomalies can be severely affected by out-of-plane energy, by skips in data acquisition, and by masking in structurally complex areas. The Downdip Yegua fields have been found to date by recognizing anomalous seismic signatures and delineating small closures. Future discoveries will probably result from exploration for specific reservoir intervals, perhaps in more laminated zones which do not have a characteristic seismic expression; from more sophisticated use of seismic signature analysis for direct hydrocarbon detection; and from improved data quality in known trends.

Within the overall theme of Gulf Coast growth faulting there is significant regional variability. Detailed mapping and regional seismic interpretation of selected areas in growth fault trends of onshore Texas point up this variability, which can be related to patterns of oil and gas fields and overpressure occurrence. Several basic styles of growth faulting are observed in the Ter­ tiary sequence of the Texas Gulf Coast. The most distinctive are glide-fault systems, which display a basal detachment below highly faulted and rotated, usually sand-rich and hydrocarbonbearing strata. Most glide systems show rapidly migrating highs following the basal detachment, an "escalator" model (Vicksburg, Sarita, Corsair). However, others involve domino-style extension similar to Great Basin models (Yegua, Lobo). Other areas show rotated blocks on listric faults which may sole into a deep slide plane at great depth (Frio), often downdip of ridges of mobile shale (Zapata Wilcox). Still other growth faults are only slightly listric, have slight block rotations, and may root at great depth (Dewitt Wilcox). More local growth faulting also occurs along The Pontchartrain Basin is the site of one of the largest estuarine complexes in the southeastern United States. It is well known that the same geographic factors that make southeastern Louisiana an important metropolitan and industrial region have also led to disruption of the estuarine enviornment. Pollution, development, flood abatement, and dredging have all impacted the estuary. Besides affecting the biota and water quality, the impact of these environmental pressures is reflected in the bot­ tom sediments of the lakes. As part of an ongoing study of northern Gulf of Mexico estuaries, over 120 bottom sediment samples were collected from the Pontchartrain-Maurepas estuarine complex in late 1987. Com­ parison of sediment maps generated in the present study with studies based on samples collected in 1931, 1972, 1973, and 1978 indicates that the distribution of sediment types has not chang­ ed greatly over the past 56 years. A notable exception is the south shore in the vicinity of outfall canals and the Inner Harbor Navigation Canal where sandy sediment is accumulating. Other "textural islands" of sediment with elevated sand content, discovered by the 1931 sampling of Lake Pontchartrain, persist to the present day. Lake Maurepas sediments have a significantly lower level of carbonate than Lake Pontchartrain sediments. In Lake Pontchar­ train the carbonate content increases from east to west with the the margins of salt- or shale-withdrawal basis, or as compactional faulting related to shale ridges. Factors that control structural styles must include: the nature of the pre-progradation substrate; presence of salt- or shalerelated bathymetric features on the old continental slope; the rate and spatial variation of sediment loading; and the relative excess of sedimentation over subsidence. Presence of thick mud sequences in the substrate favors shale-ridge development and glide-fault systems. Slope features localize the trend of faulting and may concentrate it over the slip-face of the slope feature. The spatial variance of sedimentation may determine the geometry of faulting, and also initiate salt or shale movement. The relative excess of sedimentation over subsidence determines the magnitude and timing of the fault systems. 'Frontera Exploraton Services, 900 NE Loop 410, San Antonio, TX 78209 highest values occurring along the south shore. The generally elevated carbonate content of the sediments probably reflects the impact of shell dredging on the estuarine complex. The anomalously high carbonate content of a few samples along the south shore, however, is probably due to the concentration of shell by wave action rather than shell dredging which is pro­ hibited in the near shore areas of the lake. Of the two lakes, Lake Pontchartrain has been impacted most by heavy metals carried in effluent, particularly along the south shore due to the numerous outfall canals. Comparison of metal levels in the lake with values determined for Mississippi Sound indicates that Pb and Cr are elevated in lake Pontchartrain. As frequently observed in estuarine sediments, the heavy metal con­ tent of affected sediments increases with increasing clay con­ tent. Therefore, sediment samples taken at the mouths of out­ fall canals can produce erroneous estimates of the impact of ef­ fluent due to the elevated sand content. The sandy sediments in the vicinity of ou.tfall canals are the result of winnowing dur­ ing periods of high discharge storm drainage.

ABSTRACT A northwest-southeast linear zone, here named the Frio River line, about 60 miles (100 km) southwest of San Antonio separates two areas of contrasting structural and stratigraphic history. To the northeast, structures include the uplifted Llano area, the Balcones and Luling zones of normal faulting, and a narrow graben which closely outlines the landward edge of Jurassic salt. All of these features disappear southwest of the Frio River line. To the southwest are northwest-southeast low-amplitude folds of the Rio Grande foldbelt, which are similar in orientation and age to Laramide folding in northeastern Mexico. Northeast of the line, Jurassic salt was deposited over broad areas; to the southwest, seismic data suggests an erratic distribution of salt. Lower Cretaceous subsidence was marked southwest of the line, and Gulfward sliding predominated northeast of the line. Upper Cretaceous alkalic volcanics are restricted to a belt northeast of the line, and are most abundant where that belt intersects the line. Even Tertiary growth-fault styles show distinct changes across this line, probably due to a greater thickness of Upper Cretaceous shale in the south. Fragmentary evidence indicates that the line may have a pre-Late Jurassic origin, possibly as the northeastern boundary of a Mesozoic strike-slip system, or as the southeastward continuation of the Devils River Uplift. Oil and gas plays in Cretaceous rocks are different north and south of the Frio River line; the Northern Gulf is dominated by traps related to normal fault systems, while Southwest Texas contains mostly fold-related and cross-fault traps and stratigraphic traps.

The discovery of additional stratigraphic reservoirs within the already-producing Hackberry sandstones of southeast Texas can be enhanced by a thorough understanding of the complexities of both overall channel geometry and the internal heterogeneity of these sands. This geologic assessment locates major submarine channels, describes the geometries of the sandstone bodies, details the evolution of the Hackberry depositional system and discusses resulting hydrocarbon distribution.

Research Article| June 01, 1985 Westward extension of the Devils River uplift–Implications for the Paleozoic evolution of the southern margin of North America Thomas E. Ewing Thomas E. Ewing 1Bureau of Economic Geology, University of Texas, Austin, Texas 78713 Search for other works by this author on: GSW Google Scholar Author and Article Information Thomas E. Ewing 1Bureau of Economic Geology, University of Texas, Austin, Texas 78713 Publisher: Geological Society of America First Online: 01 Jun 2017 Online ISSN: 1943-2682 Print ISSN: 0091-7613 Geological Society of America Geology (1985) 13 (6): 433–436. https://doi.org/10.1130/0091-7613(1985)13<433:WEOTDR>2.0.CO;2 Article history First Online: 01 Jun 2017 Cite View This Citation Add to Citation Manager Share Icon Share Facebook Twitter LinkedIn MailTo Tools Icon Tools Get Permissions Search Site Citation Thomas E. Ewing; Westward extension of the Devils River uplift–Implications for the Paleozoic evolution of the southern margin of North America. Geology 1985;; 13 (6): 433–436. doi: https://doi.org/10.1130/0091-7613(1985)13<433:WEOTDR>2.0.CO;2 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 SocietyGeology Search Advanced Search Abstract The Devils River uplift is inferred to continue westward into Trans-Pecos Texas. Both the known Devils River uplift and the Tascotal uplift are bounded on the north by east-west fault zones (Chalk Draw and Carta Valley fault zones) separating them from Late Pennsylvanian clastic foredeep basins (Marfa and Val Verde basins). The exposed, much-shortened Marathon thrust belt may have been emplaced in the earliest Permian by gravity gliding. Meager evidence suggests that the Devils River block represents a Cambrian or Infracambrian rift and that the uplift is an aulacogen. The early Cambrian continental margin probably continued southwest into Mexico but has been displaced by Mesozoic left-lateral movement. This content is PDF only. Please click on the PDF icon to access. First Page Preview Close Modal You do not have access to this content, please speak to your institutional administrator if you feel you should have access.

Studies of the Pleasant Bayou 1 and 2 test wells and of data from the Chocolate Bayou oil and gas field have yielded the most complete picture of a geopressured geothermal aquifer system yet obtained from the Texas Gulf Coast. The principal geothermal reservoir, the C (Andrau) sandstone, has outstanding porosity and permeability owing to (1) initially high porosity resulting from deposition in a winnowed distributary-mouth bar complex, (2) enhancement of porosity by secondary leaching by acid waters, and (3) isolation from late carbonate cementation. The maturity profile obtained for the test well is anomalous, but can be modeled using various time-paleotemperature and burial-history configurations. These models fall into two groups. The first assumes the present geothe mal gradient, modified by cooling of the lower Frio section by water flow. In the second, anomalously cool paleogeothermal gradients must be enhanced by the passage of warm waters through the middle Frio section. Both models indicate a fairly late origin of secondary porosity. End_of_Article - Last_Page 1211------------

The Permian basin of West Texas and New Mexico is one of the premier hydrocarbon provinces of the world; nonetheless, little regional subsurface structural information about it has been published. Mapping at 1:250,000 on the Ellenburger horizon (Lower Ordovician), compiled for the Tectonic Map of Texas, discloses the overall geometry of Paleozoic deformation in the area. The southern Permian basin is underlain by the NNW-trending Central Basin disturbed belt of Wolfcamp age (Lower Permian), the deep Delaware basin to its west, and the shallower Midland basin to its east. The disturbed belt is highly segmented with zones of left-lateral offset. Major segments from south to north are: the Puckett-Grey Ranch zone; the Fort Stockton uplift; the Monahans transverse zone; the Andector ridges and the Eunice ridge; the Hobbs transverse zone; and the Tatum ridges, which abut the broad Roosevelt uplift to the north. East-west compression is inferred, with shortening increasing from the Tatum ridges south to the Fort Stockton uplift. The segment boundaries and transverse elements are inferred zones of strike-slip faulting. These fault zones extend both southeast and west of the disturbed belt into discrete strike-slip faults with local uplifts in compressive bends (such as the Big Lake uplift). The Midland basin is much shallower than the Delaware basin, and the uplift-to-basin transition is gradual. A belt of subtle domes and anticlines, extending northeast from Andrews County, overlies a major basement discontinuity (the Grenville Front). The disturbed belt may have originated along rift zones of either Precambrian or Cambrian age. The extent of Lower and Middle Pennsylvanian deformation is unclear; much of the Val Verde basin-Ozona arch structure may have formed then. The main Wolfcamp deformation overthrust End_Page 474------------------------------ the West Texas crustal block against the Delaware block, with local denudation of the uplifted edge and eastward-directed backthrusting into the Midland basin. Later in the Permian, the area was the center of a subcontinental bowl of subsidence--the Permian basin proper. The disturbed belt formed a pedestal for the carbonate accumulations which created the Central Basin platform. The major pre-Permian reservoirs of the Permian basin lie in large structural and unconformity-bounded traps on uplift ridges and domes. Further work on the regional structural style may help to predict fracture trends, to assess the timing of oil migration, and to evaluate intrareservoir variations in the overlying Permian giant oil fields. End_of_Article - Last_Page 475------------

Deep-water sandstones of the Hackberry Formation (Oligocene) host significant quantities of oil and gas. They remain one of the most important deep exploration targets in southeasternmost Texas; new fields producing from the Hackberry have been discovered at a steady rate from 1946 to the present. The Hackberry contains two hydrocarbon plays. The updip play is relatively shallow, oil-rich, and lies near the updip limit of deep-water deposition. Some of the fields in this play actually produce from shallow-water Frio sandstones of Hackberry age rather than from Hackberry sandstones. The downdip play is gas rich and generally geopressured. The reservoirs lie either within or on the flanks of major channel systems and are often bounded updip by small growth faults. The discontinuous distribution and complex lithofacies of these channel and fan sands demand a careful understanding of the component depositional environments in order to discover and efficiently produce hydrocarbons. The Hackberry Formation is a wedge of sand and shale with bathyal fauna that separates upper Frio sandstone and shale from middle and lower Frio shale and sand. The main sandstone lies atop a channeled unconformity at the base of the formation; some sandstones are also found locally within the shale wedge. Sandstones in a typical sand-rich channel evolve upward from a basal channel-fill sand to more widespread valley-fill deposits of interbedded sand and shale. Topmost are proximal to medial fan deposits with slightly meandering channels and overbank turbidites. This sequence suggests that the Hackberry sands were laid down by an aggrading, onlapping submarine canyon-fan complex that eroded headward into the contemporaneous Frio barrier bar-strand plain. Regional mapping and seismic i terpretation outlines a network of partly sand-filled channels extending from the strand plain toward the southeast. The downdip limits of lower Hackberry sand are not defined by available well data. The early structural history of the area is obscure, but Vicksburg-age faulting associated with continental slope sedimentation is possible. Small growth faults displace the Hackberry section less than 500 ft (150 m) and extend upward into the Miocene strata. Isopach and isolith maps indicate that the Orange, Port Neches, and Fannett salt domes were active uplifts during Frio and Anahuac deposition. Near Spindletop dome, however, only a north-south trending salt-cored ridge was present. The Hackberry channels are somewhat influenced by salt activity, but major channel axes extend across the uplifts. The genesis of the deep-water Hackberry embayment is obscure. Middle Frio strata underlying the Hackberry are neritic shelf deposits to the west but may include deeper water shales in the central and eastern parts of the area. The embayment may have formed by subsidence of a large part of the Frio-Vicksburg continental shelf with consequent canyon erosion. Alternatively, the Hackberry canyons may be analogous to canyons currently forming on the flanks of the Niger delta in an entirely deep-water regime. End_of_Article - Last_Page 458------------

ABSTRACT Oil and gas accumulation in Gulf Coast Tertiary strata is mainly controlled by regional growth faults and by salt-related structures. Salt forms the most prominent set of structures in the Houston diapir province of southeast Texas. Recent work in three study areas shows that the Tertiary growth-fault trends so well displayed along strike to the southwest continue through this salt basin as well, but have been deformed by later salt movement. In the Katy area, seismic data disclose early (pre-Wilcox) salt pillows downdip of the Cretaceous reef trend. Progradation of the lower Wilcox Rockdale delta system created a linear growth-fault trend above and seaward of the pillows. Salt stocks were injected upward from the pillows in Claiborne time and were flanked by deep withdrawal basins and turtle structures. Major oil accumulations occur over an inferred turtle structure and over deep-seated salt domes. The lower Wilcox growth-fault trend deformed by the later salt flowage is virtually unexplored, although geopressured gas production from these low-permeability deltaic reservoirs exists in adjacent areas. In Brazoria County, a major lower Frio growth-fault trend affecting the Houston delta system was deformed by later salt domes, by a salt-withdrawal basin, and by a possible turtle structure at Chocolate Bayou. A productive geopressured aquifer exists in the salt-withdrawal basin bounded by the previously formed growth faults. In Jefferson County, in contrast, salt tectonic activity and growth faulting appear to have been coeval. Early salt-cored ridges continued to rise throughout Frio deposition; growth faults occur both updip and downdip. Salt diapirism may have occurred throughout Frio time at Orange and Port Neches salt domes, but other domes such as Spindletop formed in post-Frio time. Hydrocarbons accumulated over the salt domes in growth-fault anticlines and in stratigraphic traps. Contemporaneous, low-intensity growth faulting and salt movement may be ascribed to the minimal loading imposed by the sand-poor lower and middle Frio section. Recognition that shelf-margin growth faulting preceded the development of the present pattern of domes and basins has important implication for hydrocarbon exploration. Growth faults may be migration paths for hydrocarbons; furthermore, early-formed traps, distorted by salt movement, may still be found to contain hydrocarbons. Figure 1. Regional shelf-margin trends of the Gulf Coast Basin and location of the Katy, Pleasant Bayou, and Port Arthur study areas. Map from Winker and Edwards (1983). End_Page 83-------------------------

Approximately 153 billion bbl of in-place oil have been discovered in Texas oil reservoirs. Characterization of 500 of the largest of these reservoirs (those that have cumulative oil productions of more than 10 million bbl) on the basis of geologic and engineering parameters, facilitates the grouping of Texas oil reservoirs into families or plays of similar reservoir geology and common engineering and production attributes. Basic data for each reservoir were tabulated from information in the hearing files of the Texas Railroad Commission and other public sources. Thirty variables were examined for each reservoir. Oil plays were characterized in terms of: (a) reservoir genesis, (b) petrophysical properties of the reservoir, (c) trapping mechanism, (d) drive mechanism, (e) fluid properties, (f) volume of in-place oil, (g) recoverable reserves, (h) calculated oil recovery efficiency, and (i) reservoir management practices and conventional well spacing. Most of the major Texas oil reservoirs can be grouped into 48 geological plays which account for 71% (32 billion bbl) of all Texas oil production.