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At least 91 records · Page 5Linked to original sources
USGS1998

Black shale source rocks and oil generation in the Cambrian and Ordovician of the central Appalachian Basin, USA

Nearly 600 million bbl of oil (MMBO) and 1 to 1.5 trillion ft 3 (tcf) of gas have been produced from Cambrian and Ordovician reservoirs (carbonate and sandstone) in the Ohio part of the Appalachian basin and on adjoining arches in Ohio, Indiana, and Ontario, Canada. Most of the oil and gas is concentrated in the giant Lima-Indiana field on the Findlay and Kankakee arches and in small fields distributed along the Knox unconformity. Based on new geochemical analyses of oils, potential source rocks, bitumen extracts, and previously published geochemical data, we conclude that the oils in both groups of fields originated from Middle and Upper Ordovician black shale (Utica and Antes shales) in the Appalachian basin. Moreover, we suggest that approximately 300 MMBO and many trillions of cubic feet of gas in the Lower Silurian Clinton sands of eastern Ohio originated in these same source rocks. Oils from the Cambrian and Ordovician reservoirs have similar saturated hydrocarbon compositions, biomarker distributions, and carbon isotope signatures. Regional variations in the oils are attributed to differences in thermal maturation rather than to differences in source. Total organic carbon content, genetic potential, regional extent, and bitumen extract geochemistry identify the black shale of the Utica and Antes shales as the most plausible source of the oils. Other Cambrian and Ordovician shale and carbonate units, such as the Wells Creek formation, which rests on the Knox unconformity, and the Rome Formation and Conasauga Group in the Rome trough, are considered to be only local petroleum sources. T max , CAI, and pyrolysis yields from drill-hole cuttings and core indicate that the Utica Shale in eastern and central Ohio is mature with respect to oil generation. Burial, thermal, and hydrocarbon-generation history models suggest that much of the oil was generated from the Utica-Antes source in the late Paleozoic during the Alleghanian orogeny. A pervasive fracture network controlled by basement tectonics aided in the distribution of oil from the source to the trap. This fracture network permitted oil to move laterally and stratigraphically downsection through eastward-dipping, impermeable carbonate sequences to carrier zones such as the Middle Ordovician Knox unconformity, and to reservoirs such as porous dolomite in the Middle Ordovician Trenton Limestone in the Lima-Indiana field. Some of the oil and gas from the Utica-Antes source escaped vertically through a partially fractured, leaky Upper Ordovician shale seal into widespread Lower Silurian sandstone reservoirs.

Ohio, Ontario↗
USGS1998

Radiogenic heat production in sedimentary rocks of the Gulf of Mexico basin, south Texas

Radiogenic heat production within the sedimentary section of the Gulf of Mexico basin is a significant source of heat. Radiogenic heat should be included in thermal models of this basin (and perhaps other sedimentary basins). We calculate that radiogenic heat may contribute up to 26% of the overall surface heat-flow density for an area in south Texas. Based on measurements of the radioactive decay rate of a-particles, potassium concentration, and bulk density, we calculate radiogenic heat production for Stuart City (Lower Cretaceous) limestones, Wilcox (Eocene) sandstones and mudrocks, and Frio (Oligocene) sandstones and mudrocks from south Texas. Heat production rates range from a low of 0.07 ±0.01 µW/m 3 in clean Stuart City limestones to 2.21 ±0.24 µW/m 3 in Frio mudrocks. Mean heat production rates for Wilcox sandstones, Frio sandstones, Wilcox mudrocks, and Frio mudrocks are 0.88, 1.19, 1.50, and 1.72 µW/m3, respectively. In general, the mudrocks produce about 30-40% more heat than stratigraphically equivalent sandstones. Frio rocks produce about 15% more heat than Wilcox rocks per unit volume of clastic rock (sandstone/mudrock). A one-dimensional heat- conduction model indicates that this radiogenic heat source has a significant effect on subsurface temperatures. If a thermal model were calibrated to observed temperatures by optimizing basal heat-flow density and ignoring sediment heat production, the extrapolated present-day temperature of a deeply buried source rock would be overestimated.

American Association of Petroleum Geologists Bulle↗
USGS1998

Bluebell field, Uinta basin: Reservoir characterization for improved well completion and oil recovery

Bluebell field is the largest oil-producing area in the Uinta basin of northern Utah. The field includes over 300 wells and has produced 137 MMbbl oil and 177 bcf gas from fractured Paleocene-Eocene lacustrine and fluvial deposits of the Green River and Wasatch (Colton) formations. Oil and gas are produced at depths of 10,500-13,000 ft (3330-3940 m), with the most prolific reservoirs existing in overpressured sandstones of the Colton Formation and the underlying Flagstaff Member of the lower Green River Formation. Despite a number of high-recovery wells (1-3 MMbbl), overall field recovery remains low, less than 10% original oil in place. This low recovery rate is interpreted to be at least partly a result of completion practices. Typically, 40-120 beds are perforated and stimulated with acid (no proppant) over intervals of up to 3000 ft (900 m). Little or no evaluation of individual beds is performed, preventing identification of good-quality reservoir zones, water-producing zones, and thief zones. As a result, detailed understanding of Bluebell reservoirs historically has been poor, inhibiting any improvements in recovery strategies. A recent project undertaken in Bluebell field as part of the U.S. Department of Energy's Class 1 (fluvial-deltaic reservoir) Oil Demonstration program has focused considerable effort on reservoir characterization. This effort has involved interdisciplinary analysis of core, log, fracture, geostatistical, production, and other data. Much valuable new information on reservoir character has resulted, with important implications for completion techniques and recovery expectations. Such data should have excellent applicability to other producing areas in the Uinta basin with reservoirs in similar lacustrine and related deposits.

Utah↗
USGS1980

Porosity evolution of upper Miocene reefs, Almeria Province, southern Spain

Sea cliffs 40 km east of Almeria, southeastern Spain, expose upper Miocene reefs and patch reefs of the Plomo formation. These reefs are formed of scleractinian corals, calcareous algae, and mollusks. The reef cores are as much as 65 m thick and several hundred meters wide. Fore-reef talus beds extend 1,300 m across and are 40 m thick. The reefs and reef breccias are composed of calcitic dolomite. They lie on volcanic rocks that have a K-Ar date of 11.5 m.y. and in turn are overlain by the upper Miocene Vicar Formation. In the reef cores and fore-reef breccia beds, porosity is both primary and postdepositional. Primary porosity is of three types: (a) boring clam holes in the scleractinian coral heads, cemented reef rocks, and breccias; (b) intraparticle porosity within the corals, Halimeda plates, and vermetid worm tubes; and (c) interparticle porosity between bioclastic fragments and in the reef breccia. Postdepositional moldic porosity was formed by the solution of aragonitic material such as molluscan and coral fragments. The Plomo reef carbonate rocks have high porosity and permeability, and retain a great amount of depositional porosity. Pores range in size from a few micrometers to 30 cm. The extensive intercrystalline porosity and high permeability resulted from dolomitization of micritic matrix. Dolomite rhombs are between 10 and 30 µ across. More moldic porosity was formed by the dissolution of the calcite bioclasts. Some porosity reduction has occurred by incomplete and partial sparry calcite infilling of interparticular, moldic, and intercrystalline voids. The high porosity and permeability of these reefs make them important targets for petroleum exploration in the western Mediterranean off southern Spain. In these offshore areas in the subsurface the volcanic ridge and the Plomo reef complex are locally onlapped or overlapped by 350 m or more of Miocene(?) and Pliocene fine-grained sedimentary rocks. The possibility exists that the buried Plomo reef deposits may form traps for oil and gas in the offshore areas southwest of the type locality. Stratigraphic traps also may occur where the Neogene sequence above the Plomo reef complex onlaps the volcanic ridge.

Almeria Province↗
USGS1980

Organic composition of some Upper Cretaceous shale, Powder River Basin, Wyoming

The lower Upper Cretaceous strata in northeastern Wyoming, which have yielded major quantities of oil and gas, were sampled at boreholes in Converse, Johnson, and Weston Counties. Cores of noncalcareous shale of largely nearshore-marine origin were obtained from the Frontier Formation and the overlying Cody Shale at depths of 3,780.6 to 3,879.9 m in Converse County, near the axis of the Powder River basin, and at depths of less than 320 m in Johnson County, on the western flank of the basin. Cores of calcareous and noncalcareous shale representing offshore-marine and nearshore-marine environments were acquired from the Belle Fourche Shale, Greenhorn Formation, and Carlile Shale at depths of less than 270 m in Weston County, on the eastern flank of the Powder River basin. Analyses of the shale for organic carbon content, total pyrolytic hydrocarbon yield, volatile hydrocarbon content, temperature of maximum pyrolytic yield, and vitrinite reflectance indicate that the amount and character of the organic matter in the sampled rocks is related to the content of calcium carbonate, the depositional environment, and the burial depth of the strata. On the east flank of the Powder River basin, calcareous shale of offshore-marine origin contains abundant hydrogen-rich organic matter derived mainly from aquatic plants. Noncalcareous shale of largely nearshore-marine origin, on the west flank of the basin, locally contains significant hydrogen-poor organic matter derived mostly from land plants. The noncalcareous, nearshore-marine shale in the middle of the basin probably contained similar amounts of hydrogendeficient organic matter prior to deep burial and thermal alteration. The calcareous shale in Weston County is a potentially rich source of oil and gas, but it is thermally immature and is in a very early stage of the hydrocarbon-generation process. The noncalcareous shale in Johnson County is a potential source rock for gas, but also is in an early stage of thermal alteration. In Converse County, the sampled beds are thermally mature and have generated hydrocarbons. The extent of this contribution of hydrocarbons to the commercial petroleum occurrences of the area can be inferred from the composition of the original organic matter in the beds. Furthermore, the degree of thermal alteration of the organic matter at these localities indicates that the depth of the sampled strata was never as great on the flanks of the Powder River basin as in the basin center.

Wyoming↗
USGS1980

Shallow, low-permeability reservoirs of northern Great Plains: Assessment of their natural gas resources.

Major resources of natural gas are entrapped in low-permeability, low-pressure reservoirs at depths less than 4,000 ft (1,200 m) in the northern Great Plains. This shallow gas is the product of the immature stage of hydrocarbon generation and is referred to as biogenic gas. Prospective low-permeability, gas-bearing reservoirs range in age from late Early to Late Cretaceous and include most of the section from the base of the Mowry Shale to the top of the Judith River Formation. For detailed examination, the potential reservoir section was divided into five intervals represented by one or more formations and their correlatives. The intervals selected correspond to (1) Mowry Shale, (2) Belle Fourche Shale and Greenhorn Formation, (3) Carlile Shale, (4) Niobrara and Telegrap Creek Formations and Eagle Sandstone, and (5) Claggett Shale and Judith River Formation and their equivalents. Within each interval, several different facies are developed. The following facies were identified and mapped for each interval: nonmarine rocks, coastal sandstones, shelf sandstones, siltstones, shales, and chalks. Two types of shelf sandstone were differentiated but generally not mapped separately because of lack of well log control. The "sand ridge" type has reservoir properties comparable to coastal sandstones and occurs as isolated tongues as much as 75 ft (23 m) thick. The second type of shelf sandstone is in beds commonly less than 1 in. (3 cm) thick which are interbedded with shale and contain a high content of allogenic silt- and clay-size material. It is impossible to differentiate these individual beds on conventional well logs. The siltstone and shale facies are grouped to ether because conventional logs cannot distinguish between these two rock types, particularly when they are interbedded. For future evaluation of natural gas resources from low-permeability reservoirs, it will be necessary to differentiate between the siltstone and shale facies and to identify individual beds, particularly very thin ones, within the shelf sandstone facies. Each facies contains distinct reservoir types, some of which are low in permeability. The most promising low-permeability reservoirs are developed in the shelf sandstone, siltstone, and chalk facies. Reservoirs within these facies are particularly attractive because they are enveloped by thick sequences of shale which serve as both a source and a seal for the gas. When naturally fractured, these shales also may be low-productivity gas reservoirs similar to the Devonian shales of the Appalachian basin. In addition, facies with low-permeability reservoirs are present over most of the study area when maps for all of the intervals are combined. Natural gas is produced from low-permeability reservoirs in the northern Great Plains in the southern part of western Canada. Established production covers an area of approximately 8,000 sq mi (20,700 sq km) where reported recoverable reserves average as much as 2 Bcf sq mi. Using these reserve data as an analog, the United States portion may contain resources of natural gas in excess of 100 Tcf. The volume of recoverable gas in the United States will depend on the development of improved recovery technology and higher gas prices relative to costs.

northern Great Plains↗
USGS1980

Origin of gasoline-range hydrocarbons and their migration by solution in carbon dioxide in Norton basin, Alaska.

Carbon dioxide from a submarine seep in Norton Sound, Alaska, carries a minor component of gas- and gasoline-range hydrocarbons. The molecular and isotopic compositions of the hydrocarbon gases and the presence of gasoline-range hydrocarbons indicate that these molecules are derived from thermal alteration of marine and/or nonmarine organic matter buried within Norton basin. In the gasoline-range hydrocarbons, individual cyclic and branched-chain molecules are much more abundant than straight-chain hydrocarbons. This distribution suggests that the hydrocarbon mixture is an immature, petroleumlike condensate of lower temperature origin than normal crude oil. The submarine seep provides a natural example in support of a carbon dioxide solution transport mechanism thought to be operative in the migration of hydrocarbons in certain reservoirs.

Alaska↗
USGS1980

Biogenic and thermogenic origins of natural gas in Cook Inlet basin, Alaska.

Two types of natural gas occurrences are present in the Cook Inlet basin. The major reserves (1.8 × 10 11 m 3 ) occur in shallow (less than 2,300 m), nonassociated dry gas fields that contain methane with ^dgr 13 C in the range of -63 to -56 per mil. These gas fields are in sandstones interbedded with coals of the Sterling and Beluga Formations; the gas fields are interpreted as biogenic in origin. Lesser reserves (1.1 × 10 10 m 3 ) of natural gas are associated with oil in the deeper Hemlock Conglomerate at the base of the Tertiary section; associated gas contains methane with ^dgr 13 C of about -46 per mil. The gases associated with oil in the Hemlock Conglomerate are thermogenic in origin.

Alaska↗
USGS1980

Petroleum geology of Kodiak Shelf, Alaska.

Organic geochemical data show that Cenozoic rocks on Kodiak Island, in Albatross basin, and under the continental slope generally contain less than 0.5 wt. % organic carbon. Moreover, kerogen from all rocks analyzed is predominantly (60 to 100%) herbaceous; woody and coaly kerogens are present in secondary (20 to 40%) amounts. Most strata in shelf basins are thermally immature; however, Eocene and Oligocene strata, which probably floor the shelf basins, are mature on the basis of comparison with coeval strata onshore. Eocene and Oligocene rocks have poor reservoir properties; the best reservoirs are probably in upper Miocene or Pliocene and younger rocks. Potential traps for hydrocarbons include Tugidak uplift, parts of Albatross Bank, structures in the central-shelf upli t, and Portlock anticline. Overall, unless hydrocarbon source rock properties improve offshore, gas and gas condensate are the most likely hydrocarbons to have been generated.

Alaska↗
USGS1980

Organic content of Devonian shale in western Appalachian basin

In the organic-rich facies of the Devonian shale in the western part of the Appalachian basin, the distribution of organic matter provides an indirect measure of both gas in place and the capacity of the shale to supply gas to permeable pathways.The boundary between organic-rich ('black') and organic-poor ('gray') facies is defined here as 2% organic content by volume. The thickness of organic-rich facies ranges from 200ft in central Kentucky to 1000ft along the Kentucky-West Virginia border. The average content of the organic-rich facies increases from 5% by volume on the edge to 16% in central Kentucky. The net thickness of organic matter in the organic-rich facies shows the amount of organic material in the shale, and is the most fundamental of the organic-content characterizations. Net thickness of organic matter ranges between 20 and 80ft (6.1 and 24.4m) within the mapped area.-from Author

kentucky, New York, Ohio, Pennsylvania, Virginia, ↗
USGS1981

Northwest margin of California continental borderland: Marine geology and tectonic evolution

The northwest margin of the California continental borderland consists mainly of two northwest-trending pre-Neogene lithologic belts blanketed by Miocene and younger strata. These belts, which are lithologically and structurally correlated with the Franciscan Complex and Great Valley sequence of northern California, are interpreted to represent facies corresponding to the subduction complex and forearc-basin deposits of a late Mesozoic and Paleogene continental-margin arc-trench system. The outer belt, which forms the acoustic basement underlying the continental slope and Patton Ridge, is characterized by: (1) moderately high compressional velocities (5.1 to 6.2 km/sec), (2) discordant and discontinuous seismic reflectors, and (3) nonfossiliferous and diverse rock types t at range in metamorphic grade from zeolite-bearing arkosic sandstone to blueschist. Landward, the inner Great Valley sequence belt underlies Santa Rosa-Cortes Ridge and Santa Cruz and San Nicolas Basins; in contrast to the outer belt, this belt is characterized by: (1) intermediate compressional velocities (4.5 to 4.6 km/sec), (2) concordant and relatively continuous reflectors, and (3) a thick turbidite sequence of relatively undeformed and unmetamorphosed fossiliferous Cretaceous and Paleogene strata. The inner belt overlies a 6.6-km/sec layer that is probably oceanic crust, a relation consistent with the hypothesis that trapped old oceanic crust underlies the forearc basins along parts of some convergent margins. Well-developed wrench-fault structures in overlying Miocene strata record a transition from Paleogene subduction to Neogene transform faulting. Related events include widespread andesitic to dacitic volcanism and concurrent uplift and erosion of Miocene and older rocks. The proximity of these Miocene silicic volcanic rocks to the paleotrench (< 20 km) is best explained as resulting from passage of the southward-migrating Rivera ridge-fault-trench triple junction along the margin. On the basis of the age of the adjacent sea floor, passage of this triple junction occurred about 17 m.y. ago, a date that corresponds closely to the inception of volcanism and uplift in the northwest margin of the borderland. A widespread unconformity that separates highly deformed lower and lower middle iocene strata from relatively undeformed younger strata is assumed to mark the subsequent onset of wrench faulting. The timing of volcanism and uplift, and of the slightly younger wrenching event, closely matches the plate-tectonic model of Atwater and Molnar if the northwest margin of the borderland is restored to an earlier tectonic setting off Baja California, approximately 260 km southeast of its present position.

California↗
USGS1981

Upper Oligocene evaporites in basin fill of Sevier Desert region, western Utah

The basin fill beneath the Sevier Desert of western Utah contains evaporites that were deposited in a broad closed basin. All of the basin fill penetrated by the Gulf Oil 1 Gronning contains abundant volcanic detritus and its alteration products of Cenozoic age. Fission-track dating of tuffaceous sandstone yields ages of 26-28 m.y. Fossil pollen from mudstone in the evaporite-bearing strata includes forms no older than late Oligocene, in good agreement with the fission-track ages. Thus the age of evaporites is late Oligocene and younger. Anhydrite is present throughout approximately 900m of volcaniclastic rocks in the lower part of the section cut by the Gulf hole. Fossil pollen are indicative of an arid to semiarid flora.-from Authors

Utah↗
USGS1981

Munsell color value as related to organic carbon in Devonian shale of Appalachian basin

Comparison of Munsell color value with organic carbon content of 880 samples from 50 drill holes in the Appalachian basin shows that a power curve is the best fit for the data. A color value below 3 to 3.5 indicates the presence of organic carbon but is meaningless in determining the organic carbon content because a large increase in amount of organic carbon causes only a minor decrease in color value. Above 4, the color value is one of the factors that can be used in calculating the organic content. For samples containing equal amounts of organic carbon, calcareous shale containing more than 5% calcite is darker than shale containing less than 5% calcite.

American Association of Petroleum Geologists Bulle↗
USGS1981

Two oil types on North slope of Alaska: Implications for exploration

Forty oil samples from across the North Slope of Alaska have been analyzed by the U.S. Bureau of Mines and the U.S. Geological Survey. Results of these analyses suggest two separate genetic oil types. The first, the Simpson-Umiat oil type, occurs in reservoir rocks of Cretaceous and Quaternary age and includes oil from seeps in the Skull Cliff, Cape Simpson, Manning Point, and Ungoon Point areas, and oils from Wolf Creek test 3, and the Cape Simpson and Umiat oil fields. These are higher gravity, low-sulfur oils with no, or slight, odd-numbered n-alkane predominance and pristane to phytane ratios greater than 1.5. Also, these oils have ^dgr 13 C values ranging from -29.1 to -27.8 parts per thousand (ppt) and ^dgr 34 S values from -10.3 to -4.9 ppt. The s cond type, the Barrow-Prudhoe oil type, occurs in reservoir rocks of Carboniferous to Cretaceous age and includes oils from South Barrow gas field, Prudhoe Bay oil field, and the Fish Creek test well 1. Physical properties of Barrow-Prudhoe oils are variable, but in general the oils are medium-gravity, high-sulfur oils with slight even-numbered n-alkane predominance and pristane to phytane ratios less than 1.5. Also these oils have ^dgr 13 C values of -30.3 to -29.8 ppt and ^dgr 34 S values from -30.0 to +2.1 ppt. The two types are believed to originate from different source rocks; the Barrow-Prudhoe type may have originated from a carbonate or other iron-deficient source rock, and the Simpson-Umiat type from a siliciclastic source rock. Occurrences of the two oil types when outlined on a map, indicate at least two areas for additional exploration: for the Barrow-Prudhoe type, in stratigraphic traps along and adjacent to the Barrow arch, and for the Simpson-Umiat type, in Cretaceous rocks along the trend between the Simpson and Umiat oil fields and in Cretaceous and Tertiary rocks from Prudhoe Bay field to the William O. Douglas Arctic Wildlife Range.

Alaska↗
USGS1997

Sequence stratigraphic distribution of coaly rocks: Fundamental controls and paralic examples

Significant volumes of terrigenous organic matter can be preserved to form coals only when and where the overall increase in accommodation approximately equals the production rate of peat. Accommodation is a function of subsidence and base level. For mires, base level is very specifically the groundwater table. In paralic settings, the groundwater table is strongly controlled by sea level and the precipitation/evaporation ratio. Peat accumulates over a range of rates, but always with a definite maximum rate set by original organic productivity and space available below depositional base level (groundwater table). Below a threshold accommodation rate (nonzero), no continuous peats accumulate, due to falling or low groundwater table, sedimentary bypass, and extensive erosion by fluvial channels. This is typical of upper highstand, lowstand fan, and basal lowstand-wedge systems tracts. Higher accommodation rates provide relatively stable conditions with rising groundwater tables. Mires initiate and thrive, quickly filling local accommodation vertically and expanding laterally, favoring accumulation of laterally continuous coals in paralic zones within both middle lowstand and middle highstand systems tracts. If the accommodation increase balances or slightly exceeds organic productivity, mires accumulate peat vertically, yielding thicker, more isolated coals most likely during of late lowstand-early transgressive and late transgressive-early highstand periods. At very large accommodation increases, mires are stressed and eventually inundated by clastics or standing water (as in middle transgressive systems tracts). These relations should be valid for mires in all settings, including alluvial, lake plain, and paralic. The tie to sea level in paralic zones depends on local subsidence, sediment supply, and groundwater regimes. These concepts are also useful for investigating the distribution of seal and reservoir facies in nonmarine settings.

American Association of Petroleum Geologists Bulle↗
USGS1997

Geochemistry of oils from the Junggar basin, northwest China

The Junggar basin of northwestern China is a structural basin containing a thick sequence of Paleozoic-Pleistocene rocks with estimated oil reserves of as much as 5 billion bbl. Analyses of 19 oil samples from nine producing fields and two oil-stained cores in the Junggar basin revealed the presence of at least five genetic oil types. The geochemistry of the oils indicates source organic matter deposited in fresh to brackish lake and marine environments, including coaly organic matter sources. The volumetrically most important oil type discovered to date is produced from Late Carboniferous-Middle Triassic reservoirs in the giant Karamay field and nearby fields located along the northwestern margin of the Junggar basin. Oil produced from the Mahu field, located downdip in a depression east of the Karamay field, is from a different source than Karamay oils. Unique oil types are also produced from an upper Permian reservoir at Jimusar field in the southeastern part of the basin, and from Tertiary (Oligocene) rocks at Dushanzi field and Lower Jurassic rocks at Qigu field, both located along the southern margin of the basin. Previous studies have demonstrated the presence of Upper Permian source rocks, and the possibility of Mesozoic or Tertiary sources has been proposed, but not tested by geochemical analysis, although analyses of some possible Jurassic coal source rocks have been reported. Our findings indicate that several effective source rocks are present in the basin, including local sources of Mesozoic or younger age for oil accumulations along the southern and southeastern margins of the basin. Future exploration or assessment of petroleum potential of the basin can be improved by considering the geological relationships among oil types, possible oil source rocks, and reservoirs.

Junggar Basin↗
USGS1997

Relationships among in-situ stress, fractures and faults, and fluid flow: Monterey formation, Santa Maria basin, California

We used borehole televiewer (BHTV) data from four wells within the onshore and offshore Santa Maria basin, California, to investigate the relationships among fracture distribution, orientation, and variation with depth and in-situ stress. Our analysis of stress-induced well-bore breakouts shows a uniform northeast maximum horizontal stress (S H max ) orientation in each well. This direction is consistent with the S H max direction determined from well-bore breakouts in other wells in this region, the northwest trend of active fold axes, and kinematic inversion of nearby earthquake focal plane mechanisms.

California↗