Porous Dolomite Research Articles

Tectonic-hydrothermal brecciation associated with calcite precipitation and permeability destruction in Mississippian carbonate reservoirs, Montana and Wyoming

The Mississippian Madison Formation contains abundant fracture zones and breccias that are hydrothermal in origin based on their morphology, distribution, and geochemical signature. The hydrothermal activity is related to crustal shortening during the Laramide orogeny. Brecciation is accompanied by dedolomitization, late-stage calcite precipitation, and porosity occlusion, especially in outcrop dolomites. The tectonic-hydrothermal late-stage calcite reduces permeability in outcrops and, potentially, high-quality subsurface reservoir rocks of the subsurface Madison Formation, Bighorn Basin. The reduction of permeability and porosity is increased along the margins of the Bighorn Basin but not predictable at outcrop scale. The destruction of porosity and permeability by hydrothermal activity in the Madison Formation is unique in comparison to studies that document enhanced porosity and permeability and invoke hydrothermal dolomitization models. Hydrothermal breccias from the Owl Creek thrust sheet are classified into four categories based on fracture density, calcite volume, and clast orientation. Shattered breccias dominate the leading edge of the tip of the Owl Creek thrust sheet in the eastern Owl Creek Mountains, where tectonic deformation is greatest, whereas fracture, mosaic, and chaotic breccias occur throughout the Bighorn Basin. The breccias are healed by calcite cements with 18O values ranging between 26.5 and 15.1 Peedee belemnite (PDB), indicating that the cements were derived from isotopically depleted fluids with elevated temperatures. In the chaotic and mosaic breccia types, large rotated and angular clasts of the host rock float in the matrix of coarse and nonzoned late-stage calcite. This appearance, combined with similar 18O values across even large calcite veins, indicates that the calcite precipitated rapidly after brecciation. Values for 13C (5–12 PDB) from the frontal part of the Owl Creek thrust sheet indicate equilibrium between methane and CO2-bearing fluids at about 180C. Fluid inclusions from the eastern basin margin show that these cements are in equilibrium with fluids having minimum temperatures between 120 and 140C and formed from relatively low-salinity fluids, less than 5 wt.% NaCl. Strontium isotope ratios of these hydrothermal fluids are more radiogenic than proposed values for Mississippian seawater, suggesting that the fluids mixed with felsic-rich basement before migrating vertically into the Madison Formation. We envisage that the tectonic-hydrothermal late-stage calcite-cemented breccias and fractures originated from undersaturated meteoric groundwaters that migrated into the burial environment while dissolving and incorporating Ca2+ and and radiogenic Sr from the dissolution of the surrounding carbonates and the felsic basement, respectively. In the burial environment, these fluids were heated and mixed with hypersaline brines from deeply buried parts of the basement. Expulsion of these fluids along basement-rooted thrust faults into the overlying strata, including the Madison Formation, occurred most likely during shortening episodes of the Laramide orogeny by earthquake-induced rupturing of the host rock. The fluids were injected forcefully and in an explosive manner into the Madison Formation, causing brecciation and fracturing of the host rock, whereas the subsequent and sudden decrease in the partial pressure of CO2 caused the rapid precipitation of calcite cements. The explosive nature of hydrothermal fluid migration ultimately produces heterogeneities in reservoir-quality carbonates. In general, flow units in the Madison Formation are related to sequence boundaries, which create vertical subdivisions in the porous dolomite. The late-stage calcite cement surrounds hydrothermal breccia clasts and invades the dolomite, reducing porosity and permeability of the reservoir-quality rock. As a consequence, horizontal flow barriers and compartments are established that are locally unpredictable in their location and extent and regionally predictable along the margins of the Bighorn Basin.

Variants of the strain-amplitude dependence of elastic wave velocities in rocks under pressure

The dependence of the compressional and shear wave velocities on strain amplitude in the Madra dolomites is studied. The experiments were performed using an ultrasonic pulse transmission technique (f = 1 MHz) with a uniaxial pressure of P = 1–60 MPa. An amplitude dependence of wave velocity in the range ed ~ (1–3) × 10−6 under a pressure of 5–20 MPa is found. The compressional velocity depends on strain amplitude but the shear velocity does not depend on amplitude change. Determined by the first arrival time, the compressional velocity increases with amplitude. However, if the compressional velocity is determined by the measurement of peak time, the velocity decreases with amplitude. For the upward and downward pressure, the curve Vp(Pax) exhibits open hysteresis, yielding a residual component of velocity. An intersection of the branches of the hysteretic loop is observed in more porous dolomites in comparison with less porous dolomite. This intersection is manifested most in the residual components of the dynamic bulk modulus and Poisson's ratio. The dynamic parameters can be used as is supposed as additional criteria in a geological interpretation.

The sequence stratigraphy, sedimentology, and economic importance of evaporite–carbonate transitions: a review

Abstract World-class hydrocarbon accumulations occur in many ancient evaporite-related basins. Seals and traps of such accumulations are, in many cases, controlled by the stratigraphic distribution of carbonate–evaporite facies transitions. Evaporites may occur in each of the systems tracts within depositional sequences. Thick evaporite successions are best developed during sea level lowstands due to evaporative drawdown. Type 1 lowstand evaporite systems are characterized by thick wedges that fill basin centers, and onlap basin margins. Very thick successions (i.e. saline giants) represent 2nd-order supersequence set (20–50 m.y.) lowstand systems that cap basin fills, and provide the ultimate top seals for the hydrocarbons contained within such basins. Where slope carbonate buildups occur, lowstand evaporites that onlap and overlap these buildups show a lateral facies mosaic directly related to the paleo-relief of the buildups. This facies mosaic, as exemplified in the Silurian of the Michigan basin, ranges from nodular mosaic anhydrite of supratidal sabkha origin deposited over the crests of the buildups, to downslope subaqueous facies of bedded massive/mosaic anhydrite and allochthonous dolomite–anhydrite breccias. Facies transitions near the updip onlap edges of evaporite wedges can provide lateral seals to hydrocarbons. Porous dolomites at the updip edges of lowstand evaporites will trap hydrocarbons where they onlap nonporous platform slope deposits. The Desert Creek Member of the Paradox Formation illustrates this transition. On the margins of the giant Aneth oil field in southeastern Utah, separate downdip oil pools have accumulated where dolomudstones and dolowackestones with microcrystalline porosity onlap the underlying highstand platform slope. Where lowstand carbonate units exist in arid basins, the updip facies change from carbonates to evaporite-rich facies can also provide traps for hydrocarbons. The change from porous dolomites composed of high-energy, shallow water grainstones and packstones to nonporous evaporitic lagoonal dolomite and sabkha anhydrite occurs in the Upper Permian San Andres/Grayburg sequences of the Permian basin. This facies change provides the trap for secondary oil pools on the basinward flanks of fields that are productive from highstand facies identical to the lowstand dolograinstones. Type 2 lowstand systems, like the Smackover Limestone of the Gulf of Mexico, show a similar relationship. Commonly, these evaporite systems are a facies mosaic of salina and sabkha evaporites admixed with wadi siliciclastics. They overlie and seal highstand carbonate platforms containing reservoir facies of shoalwater nonskeletal and skeletal grainstones. Further basinward these evaporites change facies into similar porous platform facies, and contain separate hydrocarbon traps. Transgressions in arid settings over underfilled platforms (e.g. Zechstein (Permian) of Europe; Ferry Lake Anhydrite (Cretaceous), Gulf of Mexico) can result in deposition of alternating cyclic carbonates and evaporites in broad, shallow subaqueous hypersaline environments. Evaporites include bedded and palmate gypsum layers. Mudstones and wackestones are deposited in mesosaline, shallow subtidal to low intertidal environments during periodic flooding of the platform interior. Highstand systems tracts are characterized by thick successions of m-scale, brining upward parasequences in platform interior settings. The Seven Rivers Formation (Guadalupian) of the Permian basin typifies this transition. An intertonguing of carbonate and sulfates is interpreted to occur in a broad, shallow subaqueous hypersaline shelf lagoon behind the main restricting shelf-edge carbonate complex. Underlying paleodepositional highs appear to control the position of the initial facies transition. Periodic flooding of the shelf interior results in widespread carbonate deposition comprised of mesosaline, skeletal-poor peloid dolowackestones/mudstones. Progressive restriction due to active carbonate deposition and/or an environment of net evaporation causes brining upward and deposition of lagoonal gypsum. Condensed sections of organic-rich black lime mudstones occur in basinal areas seaward of the transgressive and highstand carbonate platforms and have sourced significant quantities of hydrocarbons.

Reservoir characteristics of Devonian cherts and their control on oil recovery: Dollarhide field, west Texas

Approximately 70 million bbl of oil have been produced from the chert-dominated Thirtyone Formation at Dollarhide field. The Thirtyone Formation is Devonian in age and contains two reservoir intervals, an upper dolomite and a lower chert, separated by nonporous limestone. The chert reservoir contains approximately 83% of the original oil in place (OOIP) and consists of two different facies--laminated microporous chert and burrowed chert. The laminated microporous chert was apparently deposited as sponge spicule sands (grainstones) in channels and fans on the slope of the Tobosa basin. The burrowed chert facies was apparently deposited as burrowed mixtures of sponge spicules, siliceous mud, and carbonate mud in broad slope environments between fans and channels. Spicules are thought to be derived from disaggregation of siliceous sponges living on the slope. Early marine and/or meteoric diagenesis dissolved many sponge spicules and reprecipitated the silica as microcrystalline chalcedony and quartz, resulting in spicule-moldic porosity and microporosity in the originally siliceous strata. The burrowed chert underwent small-scale differential compaction that produced short, discontinuous fractures, 1-10 mm in length and 0.1-0.5 mm in width. Production from the field has been related to amounts and characteristics of the pore systems. The thickness of the porous chert ranges laterally from 0 to 80 ft (0-24 m), and pore volume (fh) ranges from 0 to 20 pore ft (0-6 pore m). The laminated microporous chert is very homogeneous and has high porosity (25-35%) and uniform permeability (5-30 md). Areas dominated by laminated microporous chert had moderate primary recovery (approximately 200,000 bbl of oil per well), excellent waterflood production (1-2.5 (Begin page 36) million bbl of oil per well), and poor 20-ac (8.1 ha) infill production (<20,000 bbl of oil per well). The burrowed chert has more heterogeneous porosity (5-30%) and permeability (<1-100 md). The dolomite also has heterogeneous pore networks that have porosities of 3-15% and measured permeabilities of less than 1-200 md. Wells having substantial amounts of porous dolomite and/or burrowed chert had moderate to good primary recovery (200,000-300,000 bbl of oil per well), moderate waterflood recovery (300,000-1,100,000 bbl of oil per well), and moderate 20-ac (8.1 ha) infill recovery (50,000-100,000 bbl of oil per well). Oil recovery from the CO2 flood is expected to average approximately 250,000 bbl per well, having slightly higher recovery (300,000 bbl) in areas that have thick laminated microporous chert and/or burrowed chert. Oil recovery from the homogeneous, laminated microporous chert during the CO2 flood is improved by large amounts of residual oil and good sweep efficiency but decreased by the previously efficient sweeping of original mobile oil by the waterflood. The CO2 recovery from the heterogeneous, burrowed chert is improved by significant amounts of unswept mobile oil but decreased by poorer sweep efficiency. As a field, primary recovery is estimated at 13% of OOIP, waterflood at 30% of OOIP, infill at 3.5% of OOIP, and CO2 flood at 11% of OOIP.

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 ft3 (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. Tmax, 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.

Permian (Wolfcampian) Admire C": New Exploratory Potential in the Northern Denver Basin"

Significant frontier exploratory potential exists in the lower Wolfcampian Admire C unit, a regionally continuous, porous dolomite interval occurring at depths of 7800-8500 ft (2379-2592 m) in western Nebraska, United States. Based on core, mud-log, thin-section, and SEM (scanning electron microscope) image analysis, as well as both regional and detailed local mapping, the Admire C has been found to be the most prospective of several reservoir zones in this region based on (1) consistency and occurrence of oil shows; (2) superior reservoir quality and distribution; and (3) established patterns of production. Continuity of the reservoir directly reflects transgressive-regressive cycles responsible for carbonate deposition in a shallow, intermittently restricted basin (Alliance basin) affected by glacio-eustatic sea level changes. Highest reservoir quality is concentrated in higher energy packstones and rare grainstones that exhibit a combination of intercrystalline, moldic, and vuggy porosity. The Admire C unit has low-to-moderate permeabilities (0.5-30 md) that restrict short-term flow capacity. A number of wells, however, have shown recoveries in the 75,000-130,000 bbl range at low and decreasing rates of annual decline, suggesting that they are in contact with a larger, more continuous reservoir than was previously thought. Source beds include black shales within the Pennsylvanian and Wolfcampian sections. Little free water exists in the Admire C zone, suggesting mobile water may have been displaced by hydrocarbon migration. A number of intriguing similarities between the Admire C and the Ordovician Red River B reservoir in the Williston basin imply that exploration strategies successful in the latter might be applied to the Admire.

Hollow carbonate pebbles: a case study of selective secondary porosity generation, Neogene, Israel

Neogene conglomerates are very common in Israel. In a few conglomerate localities in the hilly region of Galilee, northern Israel, a large number of the pebbles have internal cavities. This puzzling phenomenon has not been documented previously in Israel or elsewhere. The studied conglomerates occur as lithified, calcite-cemented lenticular beds, which alternate with reddish-brown argillaceous mudstones. The hollow pebbles constitute, in fact, only a special case of a wider range of related features. The most relevant observations related to these occurrences are the following. (1) The clasts are polymictic, consisting of various limestones, dolomites, and minor cherts. The hollow pebbles and related features, however, occur only in porous dolomites. (2) Calcitized, dedolomitic hard rims characterize all the affected pebbles. The thickness of these rims varies between a few mm and 1–2 cm. (3) In part of the affected pebbles, the dolomitic core (inside the calcitic rims) is preserved intact. In others, only the hard rim is preserved, and the core is empty. These are the hollow pebbles sensu stricto. (4) Late-stage calcite spar occurs in some of the voids and in veins that cross the groundmass of the conglomerates. The first step in the sequence of events leading to the production of the described occurrences is inferred to be the calcitization of porous dolomite pebbles, resulting in the formation of dense rims around porous cores. The next step involved the dissolution of the inner core of the pebble by acidic solutions, leaving the calcitic rims almost intact. The restriction of hollow pebbles (and related features) occurrences to conglomerate strata which are interbedded with argillaceous mudstones points to a causal relationship between the two. Accordingly, the precipitation of calcite during the first step is attributed to the establishment of anoxic microenvironments within the porewater soon after the accumulation of the argillaceous material. The reversal of conditions from carbonate precipitation to dissolution (during the second step) seems to be related to a change from reducing to oxidizing microenvironments, following the emergence of the fluviatile sediments from the aquatic environments. The critical requirements for obtaining the hollow pebbles seem, therefore, to be the presence of a ‘suitable’ lithological type of pebble, namely, porous dolomite, combined with a special sequence of depositional and diagenetic environments. The apparent rarity of this combination seems to account for the lack of documentation on this phenomenon to this date.

Geological and Reservoir Characterization of Shallow-Shelf Carbonate Fields, Southern Paradox Basin, Utah: ABSRACT

Abstract The Paradox Basin of Utah, Colorado, and Arizona contains more than 50 small oil fields producing from carbonate buildups within the Pennsylvanian (Desmoinesian) Paradox Formation. These fields typically have one to four wells with primary production ranging from 700,000 to 2,000,000 barrels (112,000-318,000 m3) of oil per field at a 15- to 20- percent recovery rate. Five of these fields (Heron North, Runway, Mule, Blue Hogan, and Anasazi) within the Navajo Nation of southeastern Utah, were chosen for case study to develop geologic reservoir models to be used for waterflood and carbon-dioxide- miscible flood simulations. Conventional cores, modern geophysical logs, reservoir data, closely spaced seismic lines, and outcrop analogs for the five case-study fields were used to determine the reservoir facies, geometric relationships, flow units, and areal extent of regional facies belts and localized hydrocarbon traps. Local scale, phylloid algal buildup facies are the dominant hydrocarbon traps. These buildups typically consist of basal platform, middle mound-core, and upper supra-mound intervals. Reservoir heterogeneity is caused by combinations of lithotypes, mound relief, flooding surfaces, and diagenesis. The basal platform contains combinations of low-permeability carbonate fabrics and is rarely productive. The mound cores are generally homogenous, with porous and permeable algal lime bafflestones. The supramounds are very heterogeneous, with lower overall permeability but higher average porosity than the underlying mound cores. This heterogeneity is due to the mixed mineralogy as well as the wide range of depositional fabrics. Primary recovery is estimated to be approximately 40 percent from the mound-core and less than 15 percent from the supra-mound intervals. Oil production rates are highest from permeable algal-lime bafflestones of the mound cores. However, most of the oil reserves reside in porous dolomites of the overlying supra-mound intervals. As oil is produced from algal-lime bafflestones, oil from the overlying dolomites continually replenishes the bafflestone pore system, resulting in a production capacity far greater than can be attributed to the mound cores alone. This study provides the basis for several areas of future work. First, waterflood and/or carbon-dioxide-miscible flood projects can be designed using models and reservoir simulations based on this study. The objective is to drive oil trapped in the supra-mound rocks into the mound-core reservoir where recovery is highest. Second, the results of this study can be used to increase recoverable reserves by identifying untapped compartments created by reservoir heterogeneity and prevent premature abandonment of numerous small fields throughout the Paradox Basin. Third, the results of this study may apply to small carbonate- buildup reservoirs in other areas in the Rocky Mountain Region, the Michigan and Illinois basins, and the Midcontinent.

AVO and Devonian reef exploration: Difficulties and possibilities

Although AVO has proven useful in hydrocarbon exploration in shallow gas sands, there are few examples of its application to carbonate exploration. This paper presents a conjecture that AVO can help differentiate between shale and porous dolomite in Devonian reefs, a critical problem in Canada where oil production from Nisku reefs in the Devonian formation accounts for a large part of industry activity. Devonian formations have generated 60% of Canadian oil production and 25% of gas production.

Can Regional Porosity Occurrence in Carbonate Slope and Basin Facies Systems be Predicted?: ABSTRACT

Subsurface carbonate depositional sequences (i.e., coeval platform-to-basin facies mosaics), which can most readily be identified by application of seismic sequence analysis, include porous units of complex geometry and occurrence. A highly sought-after occurrence of reservoir-grade porosity commonly, but not always, is associated with sequence boundaries. Therefore, porosity can be predicted to possible occur in already-lithified platform strata beneath significant unconformities of regional extent (e.g., cavernous porosity). By this method, however, the possible existence of porosity in carbonate slope and basin deposits may be overlooked because they do not lie beneath sequence-bounding unconformities insofar as they are not usually exposed subaerially during platform emergence. Yet, such facies compose locally significant hydrocarbon reservoirs in the Permian basin by virtue of high porosities and permeabilities and water-free production histories. Short of drilling or seismic wavelet analysis, can porosity in such facies be predicted a priori Reservoirs in carbonate slope and basin deposits in the Midland basin include both porous limestones and dolomites. Petrographic and geochemical studies indicate that syndepositional and shallow-burial diagenesis of such deposits mainly involved porosity reduction via calcite cementation, dolomitization, and compaction. Most of the porosity present in reservoirs in these facies was created by later dissolution in the deep-burialmore » environment as a consequence of rock interaction with connate fluids enriched in carbonic and sulfuric acid and/or organic acids generated during hydrocarbon maturation. These fluids migrated up and out from deeper parts of the basin through slope and basin deposits and into platform carbonate strata. Insofar as fluid migration pathways can be mapped or at least inferred by various means, it follows that porosity created (or destroyed) by these fluids also can be mapped predictively.« less

Dolomitization and Porosity Development in the Middle and Upper Wabamun Group, Southeast Peace River Arch, Alberta, Canada

Dolomitization and fracturing are critical to porosity development in most Wabamun Group reservoirs in the southern part of the Peace River arch. Cores from Peoria, Normandville, and Eaglesham fields and adjacent areas were examined to determine the relationship between depositional facies, dolomitization, fracturing, and porosity. Three-dimensional (3-D) seismic data indicate that most upper Wabamun dolomites are coincident with mound-like structural highs at the top of the Wabamun, with structural relief due largely to differential compaction between dolomite and adjacent limestone. The dolomite bodies generally are small, only 100-300 m across, which makes 3-D seismic data very helpful in Wabamun exploration. When this depositional/diagenetic model for dolomitization w s integrated into 3-D seismic interpretations, Canadian OccidentaPs discovery rate in the Wabamun increased from approximately 25 to 80%. Dolomitization and porosity are laterally quite variable in the Wabamun with the 200-250-m Wabamun section changing laterally from porous dolomite to nonporous limestone in less than 1 km (sometimes as little as 150 m). Two generations of replacive dolomite were identified, early near-surface and late hydrothermal. The early dolomite is facies, fabric, and mineralogy selective with some burrow fills and aragonitic mollusks being preferentially dolomitized in dolomitic limestones. Complete dolomitization is common in unfossiliferous carbonates (mudstones and peloid wackestones and packstones), which are interpreted as being deposited on paleotopographic highs and dolomitized by seawater or slightly evaporated seawater during shallow burial. Most fracturing occurred after early, repla ive dolomitization. Late hydrothermal dolomitization was not strictly facies or fabric selective. Features associated with hydrothermal dolomites include vugs, fractures, collapse breccias, white dolomite cement, anhydrite, and coarse calcite cement, although anhydrite and coarse calcite cement precipitated distinctly after hydrothermal dolomitization. Late dolomitization, karst-like dissolution and collapse apparently were localized near the margins of the early dolomites where adjacent limestones were dolomitized or dissolved. Dissolution of calcite in partially dolomitized limestones resulted in geopetal accumulations of dolomite rhombs (porous sucrosic dolomite) in some fractures and burrow fills. Hydrothermal fluids apparently moved updip through the underlying Winterburn and/or Leduc formations, an then upward through porous, early dolomites in the Wabamun, causing dolomitization of adjacent limestones and karst-like dissolution. Stable oxygen isotope ratios of the dolomites are quite variable (^dgr18O ranges from -2.0 to -11.4^pmil, PDB), supporting multiple stages of dolomitization during progressive burial.

Tectonic Evolution and Hydrocarbon Potential of the Southern Moesian Platform and Balkan-Forebalkan Regions of Northern Bulgaria

The major tectonic elements of northern Bulgaria are the east-west-trending Balkan-Forebalkan fold belt and the Moesian platform. Moderate hydrocarbon exploration potential exists in trapping geometries generated during the tectonic evolution of the region coupled with reservoir/seal pairs and source rocks within Mesozoic strata. The tectonic evolution of the region includes Early Triassic to Early Jurassic intracratonic rifting followed by multiphase compression that contracted the rift basin and produced a north vergent fold and thrust belt along the southern margin of the stable Moesian platform. Compression began during the Early Cretaceous, continued during the Paleocene, and concluded during the middle Eocene. Trap types generated during the tectonic evolution include normal fault-bounded rotated blocks in the autochthonous section and elongate, asymmetric anticlines in the allochthonous section. Triassic to Upper Jurassic Marine facies were deposited in an east-west-trending rift. Sediments deposited in a shallow foredeep, which evolved during Lower cretaceous compression, overlay the rift sequence. The Early Mesozoic rift sequence provides the depositional settings for Middle Triassic and lower Middle Jurassic source rock shales and sandstone/carbonate reservoirs ranging from Middle Triassic to Lower Cretaceous. Carbonate reservoirs generally are porous dolomites with intercrystalline, moldic, and vugular pore types interbedded with nonporous limestones. Clastic reservoirsmore » are quartz-rich sandstones with pore types that are reduced intergranular, dissolution, and microporosity. These heterogeneous reservoir targets exhibit poor to good reservoir characteristics and are overlain with sealing lithologies of variable thicknesses.« less

Integrative Analysis of a Lacustrine Carbonate Reservoir, Kambala Field, Cabinda, Angola

The presalt lacustrine rift basins of west Africa are the continued focus of exploration and development in this prolific petroleum province. Kambala field produces from the Barremian-Aptian lacustrine carbonates of the TOCA Formation. Source rocks are the rich lacustrine shales of the Bucomazi Formation. TOCA carbonates were deposited along major shorelines and around islands in large lake systems. Reservoir studies provide the necessary models and analogs to guide exploration and evaluation efforts. The TOCA reservoirs in Kambala field have been subdivided into two units. The lower TOCA is characterized by limestones and cherty dolomites, which range texturally from high-energy ooid and oncoid grainstones and packstones to lower energy ostracod wackestones and marls. The upper and lower TOCA are separated by a unit of middle Bucomazi shale. The upper TOCA is composed of thin beds of low-energy facies and thick porous carbonate units, which are pervasively dolomitized. Kambala field sits over a northwest-southeast-trending basement high. The field is bounded by intense faulting on the west and dips gently to the northeast. The faults on the eastern side are more widely spaced and have less throw than the ones on the west. Seismic amplitude maps on the upper TOCA show markedly highermore » amplitudes on the western and southern edges of the field. The high seismic amplitudes and intense faulting generally correlate with the zone of porous dolomite.« less

Characteristics, Distribution and Origin of Porosity in Shelf Dolostones: Burlington-Keokuk Formation (Mississippian), U.S. Mid-Continent

ABSTRACT Finely crystalline, massive, porous dolomites comprise 10-70% of the 50-70 m thick Burlington-Keokuk Formation (Osagean) in much of a 120,000-km2 outcrop belt crossing the Mississippian paleoshelf in parts of Iowa, Illinois and Missouri. The dolomites are products of regionally widespread, selective dolomitization of lime-mud-rich subtidal skeletal mudstone to skeletal packstone. Dolomitization was most intense and lime-mud facies are most abundant in the northwestern, inner part of the paleoshelf (SE Iowa) where dolomites comprise 50-70% of the formation. Pore systems in Burlington-Keokuk dolomites originated during the first of two main regional dolomitization events, a Middle Mississippian event responsible for the conversion of shallow-buried (30-100 m), partly lithified lime-mud-rich sediments to dolomite I. Resulting dolomites are characterized by 1) non-mimetic and sucrosic, planar-e and -s fabrics composed of 30-200 µm rhombs that have intricate concentric CL zoning, 2) abundant intercrystal and moldic pores, and 3) dissolved rather than replaced CaCO3 grains. Study with SEM shows that intercrystal and micro-intercrystal pores resulted from progressive dissolution of micrite during dolomite-I dolomitization. The second major regional dolomitization event, replacement of dolomite I by uniformly dull-red luminesci g dolomite II, had essentially no effect on the dolomite-I pore systems. A widespread, volumetrically significant (10-27%), terminal CL zone of dolomite I (TD-I zone) partly occludes intercrystal pores and lines most grain molds. The TD-I zone constrains the timing of all such porosity to the later stages of dolomite-I dolomitization rather than a later event and implies a flow system of regional extent. The source of carbonate ions for this pore-occluding dolomite appears to have been CaCO3 grains dissolved at precipitation sites, supplemented from external sources. Three pervasively dolomitized microfacies comprise up to 70% of the formation and contain > 80% of the formation's pore volume; partly to undolomitized skeletal limestones, although volumetrically important, contain 5-µm pore-size fraction, skeletal-moldic pores 17%, grain-sized vugs 11%, and intracrystal pores 2%. Micropores (< 5 µm) are chiefly micro-intercrystal and micro-moldic types and comprise 19% of total porosity on average with wide variations. They account for most measured differences between effective (core-analysis) and total (thin-section) porosity.

Reservoir Performance in Ordovician Red River Formation, Horse Creek and South Horse Creek Fields, Bowman County, North Dakota (1)

The contiguous Horse Creek and South Horse Creek fields produce oil from the Ordovician Red River Formation's D zone (equal to the C Burrowed Member). These fields produce from dolomite reservoirs at depths of about 9000 ft (3000 m) in the southern Williston basin on the northeastern flank of the southern end of the Cedar Creek anticline. Gentle (<1 degree) northeast regional dip allows oil entrapment in both areas of updip porosity pinch-out and small (<2 km diameter), low-relief (<30 m) structural closures. Each field consists of two Red River D oil pools: a stratigraphic porosity pinch-out trap (drained by 15 wells in the two fields) to the west and structural closures drained by up to 3 wells, each to the east. Reservoir rocks in both types of traps are burrowed dolomitized carbonate mudstones and wackestones deposited in open to restricted shelf environments. The best reservoir rocks occur where up to 25% porosity is present between completely dolomitized burrow fills. Reservoir-quality porosity is mainly intercrystalline and vuggy in finely crystalline dolomites, but even in the most porous intervals, permeability only locally exceeds 30 md. Amounts of porosity in wells producing from the D zone can be used to estimate a well's ultimate oil recovery when integrated with data on structural position, thickness of porous dolomite, and the nature of the fluid saturation (best indicated by bulk volume water values). Production in the structurally trapped D zone oil pools in each field, where initial water saturation was 22%, will average about 625 thousand bbl of oil/well with initially negligible water, but with increasing watercut through time. The stratigraphically trapped oil pools in the fields, where initial water saturations ranged from 32 to 66%, will average 237 thousand bbl of oil/well with higher initial watercuts, but little increase in watercut through time.

Dolomite‐rock textures and secondary porosity development in Ellenburger Group carbonates (Lower Ordovician), west Texas and southeastern New Mexico

ABSTRACTPervasive early‐ to late‐stage dolomitization of Lower Ordovician Ellenburger Group carbonates in the deep Permian Basin of west Texas and southeastern New Mexico is recorded in core samples having present‐day burial depths of 1.5–7.0 km. Seven dolomite‐rock textures are recognized and classified according to crystal‐size distribution and crystal‐boundary shape. Unimodal and polymodal planar‐s (subhedral) mosaic dolomite is the most widespread type, and it replaced allochems and matrix or occurs as void‐filling cement. Planar‐e (euhedral) dolomite crystals line pore spaces and/or fractures, or form mosaics of medium to coarse euhedral crystals. This kind of occurrence relates to significant intercrystalline porosity. Non‐planar‐a (anhedral) dolomite replaced a precursor limestone/dolostone only in zones that are characterized by original high porosity and permeability. Non‐planar dolomite cement (saddle dolomite) is the latest generation and is responsible for occlusion of fractures and pore space.Dolomitization is closely associated with the development of secondary porosity; dolomitization pre‐and post‐dates dissolution and corrosion and no secondary porosity generation is present in the associated limestones. The most common porosity types are non‐fabric selective moldic and vuggy porosity and intercrystalline porosity. Up to 12% effective porosity is recorded in the deep (6477 m) Delaware basin. These porous zones are characterized by late‐diagenetic coarse‐crystalline dolomite, whereas the non‐porous intervals are composed of dense mosaics of early‐diagenetic dolomites. The distribution of dolomite rock textures indicates that porous zones were preserved as limestone until late in the diagenetic history, and were then subjected to late‐stage dolomitization in a deep burial environment, resulting in coarse‐crystalline porous dolomites. In addition to karst horizons at the top of the Ellenburger Group, exploration for Ellenburger Group reservoirs should consider the presence of such porous zones within other Ellenburger Group dolomites.

The Role of Active and Ancient Geothermal Systems in Evolution of Grant Canyon Oil Field, Railroad Valley, Nye County, Nevada

Since discovery in 1983, the Grant Canyon field has been among the most prolific oil producers (on a per-well basis) in the US. Production through June 1990 was 12,935,630 bbl of oil, principally from two wells which in tandem have consistently yielded more than 6,000 bbl of oil per day. The field is hosted by highly porous Devonian dolomite breccia loosely cemented with hydrothermal quartz. Results of fluid-inclusion and petrographic research in progress at Grant Canyon suggest that paleogeothermal and perhaps currently circulating geothermal systems may have played a major role in oil-reservoir evolution. For example, as previously reported, the breccia-cementing quartz hosts primary aqueous, aqueous/oil, and oil fluid inclusions which were trapped at about 120C (average homogenization temperature) and document initial oil migration and entrapment as droplets or globules dispersed in dilute (< 2.2 wt.% equivalent NaCl) aqueous solutions. Additional evidence of geothermal connection is that the horst-block trap at Grant Canyon is top and side sealed by valley-fill clastic and volcanic rocks which are locally hydrothermally altered and calcite flooded. These secondary seals are enhanced by disseminated, solid asphaltic residues locally accounting for 23% (volume) of the rock. Current reservoir temperatures at Grant Canyon (120C) and the adjacentmore » Bacon Flat field (171C) attest to vigorous contemporary geothermal activity. Based on results of the authors' Grant Canyon work to date, they suggest that active and paleohydrothermal systems could be viable petroleum exploration targets in otherwise favorable terrain elsewhere in the Basin and Range.« less

Albion-Scipio and Stoney Point Fields, Michigan Basin, U.S.A.

Albion-Scipio and Stoney Point fields have produced more than 125 million barrels of oil from dolomites in the Middle Ordovician, Trenton, and Black River groups. Albion-Scipio is approximately 30 mi (48 km) long and Stoney Point is 10 mi (16 km) long; both fields are about 0.5 mi (0.8 km) wide. Porous reservoir dolomites lie in abrupt lateral contact with adjacent nonproductive regional limestones. At reservoir depth, the only structural expression is a shallow (up to 60 ft. 18 m) synclinal sag on a regional homoclinal surface. The sag is attributed to Late Silurian-Early Devonian left-lateral strike-slip motion on a reactivated basement fault. Reservoirs apparently formed as stratigraphic traps where dolomite developed above buried faults. Despite relatively poor matrix properties, initial flow tests of several hundred to several thousand BOPD are common. Fractures in core, bit drops, and lost circulation while drilling occurred commonly during field development. Apparently, an interconnected system of fractures, vugs, and caverns provides much of the deliverability and a significant part of the storage in these fields. Structure maps, fluid contacts, producing gas-oil ratios, bottom-hole pressures, and drilling data from lateral wells provide evidence that these fields can be subdivided into discrete reservoir compartments along theirmore » length. Heterogeneities are present at scales ranging from field to interwell to pore-size. Reservoir energy is supplied mainly by gas-cap expansion and gravity drainage. Lateral drilling, which has had limited success to date, holds potential for future field development.« less

Secondary Recovery from a Stromatoporoid Buildup: Devonian Duperow Formation, Ridgelawn Field, Montana: ABSTRACT

Ridgelawn field is located in Richland County, Montana, in the western part of the Williston basin. It is a multiple-pay field, with production from ordovician, Devonian, and Mississippian carbonates. Discovered in 1980, the field was recently unitized in the Devonian Duperow Formation for purposes of secondary recovery by waterflood. In this part of the Williston, the Duperow consists of a repetitive succession of shoaling-upward carbonate cycles, each deposited under increasingly restricted conditions on a shallow marine shelf. Production at Ridgelaw occurs from dolomites within one of these cycles, cycle IIIa. Three separate, laterally continuous porosity zones (here termed a, b, and c, from lowest to highest) are recognized and mapped individually in the field. The reservoir has a lensoidal geometry; porous dolomite thins and grades laterally into tight carbonate. The Duperow pool at Ridgelawn is a solution gas drive reservoir. Computer log analysis of the Duperow pay interval indicates an average true porosity of 11.8% and an average initial water saturation of 17.7%. Net pay, defined as greater than 5% crossplot porosity, averages 16.6 ft across the field. Petrographic analysis and log calibration suggests that different facies in each of the three porosity zones were preferentially dolomitized to create reservoir-qualitymore » rock; each is now a sucrosic dolomite with intercrystalline porosity. Porosity can be occluded (most often in the upper two zones b and c) by both calcite and anhydrite cements. The lowermost zone, a, is related to a stromatoporoid/coralline bank, and has excellent but highly variable porosity and permeability. The two upper zones, b and c, are more finely crystalline dolomite and represent shallower water depositional facies. Maps for each zone, including porosity, porosity-feet, net pay, and water saturation were constructed and used for equity determination in the unit.« less

Seismic detection and interpretation of porosity in Carboniferous age rocks of Kansas and Oklahoma

Many large Mississippian fields (5–130 MMBO) in south‐central Kansas and northern Oklahoma produce from discrete pods of porous chert and dolomite called “chat.” Chat has unusual acoustic properties that allow the porosity pods to be recognized on seismic sections. Integrated geologic and geophysical studies of two analog fields indicate that both reservoir quality and geometry can be interpreted from good quality seismic data. Seismic modeling on an interactive work station plays an important role in developing these interpretations.