Showing papers on "Petroleum reservoir published in 2007"

The Puguang gas field: New giant discovery in the mature Sichuan Basin, southwest China

Abstract: The giant Puguang gas field, with a proven original in-place gas volume of 350 109 m3 (12.36 TCFG), was discovered in 2003 in the eastern Sichuan fold-thrust belt of the mature Sichuan Basin, southwest China. The field is a combination structural-stratigraphic trap closed by lateral depositional change and fault closure. The trap evolved from a paleo-oil reservoir originating in the Triassic–Jurassic. The entrapment of thermal gas, which was derived from Lower–middle Silurian and Permian source rocks, occurred during deep burial in the Jurassic–Cretaceous. Tertiary–Quaternary compression transformed the paleotrap into the present gas reservoir. Gas is contained in the Lower Triassic Feixianguan and the Upper Permian Changxing reservoirs, which consist predominantly of dolomitized oolites deposited in shelf and platform-margin shoal and backreef environments. Reservoir quality is characterized by porosity of 1–29% and permeability of 0.01–9664 md, with buried depth greater than 5000 m (16,400 ft). The discovery of the Puguang field exemplifies the successful application of a new play concept and new technology in a mature basin. The discovery resulted from a shift in exploration strategy from structures to stratigraphic traps in reef and shoal dolomites and benefited from advanced high-resolution seismic techniques. The discovery will not only broaden the exploration scope in the Sichuan Basin, but also provide an excellent analog for exploration in other fold-thrust belts worldwide.

Thermal maturity of the Barnett Shale determined from well-log analysis

Abstract: Intensive development with large-scale fracturing treatments has made the Barnett Shale play (Newark East field) in the Fort Worth Basin the largest shale-gas field in the world. The Mississippian Barnett Shale is an organic-rich, self-sourced reservoir rock. Thermal maturity, thickness, and total organic carbon are the most important geological factors for commercial gas production from this shale formation. The log-derived thermal-maturity index (MI) has been developed in an effort to better understand and predict hydrocarbon phases across the basin. Maturity index was calculated using three types of open-hole logs: neutron porosity, deep resistivity, and density porosity (or bulk density). The derivation of MI is based on the hypotheses that shale gas is generated and stored locally without apparent migration from outside sources, and that the water saturation and the density of generated hydrocarbons decrease with an increase in thermal maturity. Maturity index correlates well with initial gas:oil ratios (GOR) from well production data. Based on this correlation, an empirical relationship has been demonstrated for the Fort Worth Basin. This method is useful in understanding the thermal-maturity levels of Barnett Shale source rock in the gas-generation window. Mapping MI, GOR, and gas heating value from hundreds of wells identifies the various maturity stages and areas of Barnett Shale that generate oil, condensate, wet gas, or dry gas in the Fort Worth Basin.

Petroleum systems in the offshore Xihu Basin on the continental shelf of the East China Sea

Abstract: Xihu Basin is one of the Cenozoic sedimentary basins within the continental shelf of the East China Sea, within which eight oil and gas fields and four hydrocarbon-bearing structures have been found. Our systematic analysis of potential petroleum systems in the basin has identified the Eocene Pinghu Formation as the most important source rock in the basin. The Eocene Pinghu Formation consists of mudstone and coal deposited in an embayment and tidal-flat environment and is characterized as containing type III kerogen. The Pinghu Formation is mature and, at the present time, is within the oil and wet-gas windows with determined vitrinite reflectance values in the range of 0.55–2.2% measured vitrinite reflectance (Rom). Modeling results suggest that the main stage of hydrocarbon expulsion occurred during the Miocene. The main reservoir consists of fine-grained sandstones of the Huagang and Pinghu formations deposited within shallow lacustrine and estuarine environments. The measured porosity from core samples of reservoir rock ranges from 10 to 35%, whereas permeability values range from 1 to 4000 md; both porosity and permeability decrease with depth. The mudstones of the upper Huagang and Longjing formations also occur as regional seals, which developed overpressure zones as determined by two-way sonic transit times. The overburden includes all the Oligocene, Miocene, Pliocene, and Quaternary strata. The hydrocarbon traps in the basin are mainly structural traps, including faulted blocks, faulted structural noses, and anticlines. Most traps were developed at the ends of the Eocene or Oligocene. Hydrocarbons produced from the Xihu Basin are predominantly natural gases with minor amounts of crude oil. The crude oil in the basin is characterized by a low density, low sulfur, low wax, low vanadium/nickel ratio, a low resin and asphaltene content, and a high proportion of saturated hydrocarbons. The natural gas in the basin is composed predominantly of methane, with an average C1/C1–5 ratio of 0.89 and a C1/C2–5 ratio of 8.6. Two petroleum systems have been identified in the basin: the known Pinghu-Huagang and the hypothetical Huagang-Huagang systems. The Pinghu-Huagang is the major petroleum system and most important for oil and natural gas exploration in the basin.

Accelerating the convergence of coupled : geomechanical-reservoir simulations

Abstract: The pressure variations during the production of petroleum reservoir induce stress changes in and around the reservoir. Such changes of the stress state can induce marked deformation of geological structures for stress sensitive reservoirs as chalk or unconsolidated sand reservoirs. The compaction of those reservoirs during depletion affects the pressure field and so the reservoir productivity. Therefore, the evaluation of the geomechanical effects requires to solve in a coupling way the geomechanical problem and the reservoir multiphase fluid flow problem. In this paper, we formulate the coupled geomechanical-reservoir problem as a non-linear fixed point problem and improve the resolution of the coupling problem by comparing in terms of robustness and convergence different algorithms. We study two accelerated algorithms which are much more robust and faster than the conventional staggered algorithm and we conclude that they should be used for the iterative resolution of coupled reservoir-geomechanical problem. Copyright © 2006 John Wiley & Sons, Ltd.

Compartmentalization and time-lapse geochemical reservoir surveillance of the Horn Mountain oil field, deep-water Gulf of Mexico

Abstract: Oil is produced at the Horn Mountain field (Gulf of Mexico, Mississippi Canyon blocks 126 and 127) from middle Miocene reservoirs M and J. Reservoir facies are characterized as sand-filled channels and associated overbank deposits and are positioned in combination structural and stratigraphic traps. Prior to initial production, several barriers and baffles were identified in both reservoirs by integrating geological, geophysical, petrophysical, pressure, PVT (pressure-volume-temperature relationships), and geochemical data and petroleum-filling history. A compartmentalization risk matrix was developed to facilitate and visualize the integrated evaluation of compartmentalization. During production, in addition to traditional surveillance technologies, we applied time-lapse geochemistry (TLG) to visualize petroleum sweep by monitoring changes in fluid composition and fingerprints across reservoirs. In this technology, appraisal and preproduction fluid samples are first analyzed to map fluid types across a static reservoir. Then, a surveillance program in which fluid samples are taken from producing wells at regular time intervals is designed and executed. The obtained production samples are geochemically fingerprinted and compared with preproduction fluids from the same well and surrounding wells. At Horn Mountain, interpretation of geochemical data allowed us to infer oil movement across reservoir M and helped to reevaluate reservoir models and reduce risks in managing reservoir performance. In reservoir J, an untapped compartment was identified, and an additional producer was justified for future drilling. Time-lapse geochemistry results were consistent with and complimentary to other surveillance data available to date. Our study demonstrates that TLG is a safe and cost-effective technology, which reduces uncertainties associated with other reservoir surveillance methods and appears to be valuable for reservoir management.

Porosity and lithologic estimation using rock physics and multi-attribute transforms in Balcon Field, Colombia

Abstract: This study presents the results of integrating rock physics, seismic inversion, and multi-attribute transforms to estimate reservoir rock properties of Cretaceous-aged sandstones from Balcon Field in the Neiva Basin, Upper Magdalena Valley, Colombia.

Direct pore‐scale computation of material and transport properties for North Sea reservoir rocks

Abstract: [1] This work investigates two complex, heterogeneous sandstone lithofacies in a North Sea petroleum reservoir field. We compare samples acquired by X-ray microtomography with numerically reconstructed lithofacies, obtained from a geological process based reconstruction technique. Effective material and transport properties of these digitized rocks, such as electrical resistivity, elastic moduli, fluid permeability, and magnetic resonance (NMR), are computed. The comparison largely reveals an excellent agreement of calculated effective properties between the actual and reconstructed pore structures. A dependence of the effective properties on the specific mineralogy could be investigated in case of the reconstructed rocks. Our results allow for an interpretation of trends in effective medium properties and facilitate the construction of cross-property relations for the investigated lithofacies. The present study demonstrates the potential and feasibility of combining computer generated rocks with numerical calculations to derive material and transport properties for reservoir rocks.

Impact of magmatism on petroleum systems in the sverdrup basin, canadian arctic islands, nunavut: a numerical modelling study

Abstract: Numerical modelling is used to investigate for the first time the interactions between a petroleum system and sill intrusion in the NE Sverdrup Basin, Canadian Arctic Archipelago. Although hydrocarbonexploration has been successful in the western Sverdrup Basin, the results in the NE part of thebasin have been disappointing, despite the presence of suitable Mesozoic source rocks, migrationpaths and structural/stratigraphic traps, many involving evaporites. This was explained by (i) theformation of structural traps during basin inversion in the Eocene, after the main phase ofhydrocarbon generation, and/or (ii) the presence of evaporite diapirs locally modifying the geothermalgradient, leading to thermal overmaturity of hydrocarbons. This study is the first attempt at modellingthe intrusion of Cretaceous sills in the east-central Sverdrup Basin, and to investigate how theymay have affected the petroleum system. A one-dimensional numerical model, constructed using PetroMod9.0®, investigates the effectsof rifting and magmatic events on the thermal history and on petroleum generation at the DepotPoint L-24 well, eastern Axel Heiberg Island (79°23′40″N, 85°44′22″W). The thermal history isconstrained by vitrinite reflectance and fission-track data, and by the tectonic history. The simulationidentifies the time intervals during which hydrocarbons were generated, and illustrates the interplaybetween hydrocarbon production and igneous activity at the time of sill intrusion during the EarlyCretaceous. The comparison of the petroleum and magmatic systems in the context of previouslyproposed models of basin evolution and renewed tectonism was an essential step in the interpretationof the results from the Depot Point L-24 well. The model results show that an episode of minor renewed rifting and widespread sill intrusionin the Early Cretaceous occurred after hydrocarbon generation ceased at about 220 Ma in theHare Fiord and Van Hauen Formations. We conclude that the generation potential of these deeperformations in the eastern Sverdrup Basin was not likely to have been affected by the intrusion ofmafic sills during the Early Cretaceous. However, the model suggests that in shallower sourcerocks such as the Blaa Mountain Formation, rapid generation of natural gas occurred at 125 Ma, contemporaneous with tectonic rejuvenation and sill intrusion in the east-central Sverdrup Basin.A sensitivity study shows that the emplacement of sills increased the hydrocarbon generation ratesin the Blaa Mountain Formation, and facilitated the production of gas rather than oil.

Hydromechanical modeling of critically stressed and faulted reservoirs

Abstract: A critical stress state around a faulted reservoir prior to production and injection is an important factor in the hydromechanical responses during production. The purpose of this article is to show how the long-range correlations of production rates observed in several oil fields can be reproduced with hydromechanical modeling of a faulted reservoir subjected to a critical stress state prior to production operations. The modeling implies that the permeability distribution in a reservoir that is in a critical stress state is time dependent. A finite-element model with fully coupled geomechanics and flow was used. The modeling has been applied to an approximation of the complex structure of the Gullfaks reservoir in the North Sea, including the far-field stress regimes and fault systems, although the model is considerably simplified in the search for generic, instead of field-specific, principles. Under a critical stress state, a small change of the effective stress caused by fluid-pressure changes in the reservoir is likely to trigger reservoirwide hydromechanical reactions, irrespective of whether the change was at a local scale or a reservoir scale. Such responses include fault reactivations, volumetric and shear strain changes, induced deformation evolution, and permeability changes. With a permeability enhancement model, permeability increase is expected if fault reactivation and shear strain change occur. In contrast, if the in-situ stress is not at a critical state, the reservoir reacts locally. In this case, the deformation is mainly elastic, and no permeability enhancements occur. Therefore, the impact of inelastic geomechanical interactions (particularly shear deformation) at a critical point is likely to be very influential on reservoir fluid flow. This critical-point behavior gives explanation to the widespread field observations of long-range correlations in well rates, which are inferred to be manifestations of reservoir-scale mechanical responses involving faults, instead of the local hydraulic links that Darcy flow between wells implies. Permeability changes occur during inelastic deformation despite injection pressures being much lower than the confining stress (the minimum total principal stress). The increase in permeability in the reservoir rocks is caused by the dilation normal to the surface of the faults and/or fractures, which is caused by the shearing along the faults and/or fractures, instead of hydrofracturing. This confirms that dilational shearing can develop despite the effective stress regime being compressive. Dilational shearing has a major impact on the deformation of reservoir rock during production and is an important mechanism for generating conductivity on fractures under a fluid pressure that is lower than the confining stress, possibly even in reservoirs under depletion.

New reservoir model from an old oil field: Garfield conglomerate pool, Pawnee County, Kansas

Abstract: Garfield field, an old (1948) stratigraphic trap in central Kansas, produced 10 million bbl of oil from Cherokee (Desmoinesian, Pennsylvanian) conglomerate reservoirs and from Mississippian carbonate and sandstone reservoirs. The primary reservoir rock at Garfield conglomerate pool is the Pennsylvanian basal conglomerate (PBC), unique in that it accumulated as an unstratified alluvial-fan deposit, in a subtle structural depression that may be coincident with a microplate boundary. Each of these conditions is uncommon in the northern Mid-continent. The PBC at Garfield pool is composed of pebbles, cobbles, and boulders of reworked Mississippian chert and limestone in a matrix of porous, fine-grained sandstone and sandy shale. Microporosity in the chert cobbles has access to the borehole through the porous sandstone matrix. The sandstone matrix was the product of reworking of the original shaly sand matrix and older sandstones from the substrate during short-term Desmoinesian marine transgressions of the alluvial-fan surface. Ultimately, Marmaton transgressive onlap smoothed and buried the fan surface. A near-modern alluvial fan at Rocky Flats in central Colorado provides an ideal analog for the PBC deposit at Garfield pool. The Rocky Flats fan is nearly identical in scale, areal distribution, and thickness, and its constituents are remarkably similar to conglomerate zones, which produce hydrocarbons at Garfield pool. Future exploration in north-central Kansas and southern Nebraska should focus on the occurrence of conglomerate deposits in similar depositional settings where coincident with structural depressions.

Petroleum system of Campos Basin, Brazil

Abstract: The Campos Basin, offshore Brazil, is a typical passive margin basin in the western South Atlantic, and the most prolific basin with about forty producing fields including deep-water giant fields. The Campos Basin is currently responsible for more than 80% of Brazilian oil production.The hydrocarbon accumulations are distributed throughout the stratigraphic column of the basin from Neocomian to Miocene. The most important oil accumulations in the basin are associated with deep-water fans distributed in the stratigraphic column from Cenomanian to Miocene. Almost all the hydrocarbon accumulations discovered to date are sourced mainly from Barremian to early Aptian lacustrine shales of the Lagoa Feia Formation in the pre-salt sequence. The oil pooled in the post-salt sequence migrated through a system associated with pre-salt normal faults, “salt windows” in the Aptian evaporite, listric faults and regional unconformities.The play fairway map was made based on considering the basement and the salt development, the fault distributions and the kitchen area. This map presented that the Campos Basin was divided into five structural zones. These zones could be closely related to the hydrocarbon potential. It was evaluated that the eastern part of Zone I and Zone IIa along the present day shelf edge provided more favorable condition for the hydrocarbon accumulation than other zones. The oil of Marlim Sul field is trapped in the blanket turbidites that pinch out toward the northwest landward. The thick mud deposits derived from the muddy turbidites was considered to be the important factor for establishing the stratigraphic trap.

Carbonate Sequence Stratigraphy of a Back‐Arc Basin: A Case Study of the Qom Formation in the Kashan Area, Central Iran

Abstract: The Qom Formation comprises Oligo-Miocene deposits from a marine succession distributed in the Central Basin of Iran. It is composed of five members designated as A-F. Little previous work exists on the sequence stratigraphy. Based on an integrated study of sequence stratigraphy with outcrop data, wells and regional seismic profiles, the Qom Formation is interpreted as a carbonate succession deposited in a mid-Tertiary back-arc basin. There are two second-order sequences (designated as SS1 and SS2) and five third-order sequences (designated as S1-S5). Five distinct systems tracts including transgressive, highstand, forced regressive, slope margin and lowstand have been recognized. The relationship between the sequences and lithologic sub-units has been collated and defined (S1 to S5 individually corresponding to A-C1, C2-C4, D-E, the lower and upper portions of F); a relative sea level change curve and the sequence stratigraphic framework have been established and described in detail. The coincidence of relative sea level change between that of the determined back-arc basin and the world indicates that the sedimentary cycles of the Qom Formation are mainly controlled by eustatic cycles. The variable combination of the systems tracts and special tectonic-depositional setting causally underpin multiple sequence stratigraphic framework styles seen in the carbonates of the back-arc basin revealing: (1) a continental margin basin that developed some form of barrier, characterized by the development of multiple cycles of carbonate-evaporites; (2) a flat carbonate ramp, which occurred on the southern shelf formed by the lack of clastic supply from nearby magmatic islands plus mixed siliciclastics and carbonates that occurred on the northern shelf due to a sufficient clastics supply from the land; and (3) a forced regressive stratigraphic stacking pattern that occured on the southern shelf and in basin lows due to the uplifting of the southern shelf. Thick and widespread aggradational framework limestone usually occurs in the initial sequences (S1 and S3) of the supersequence, which led to preferential oil reservoir deposition but a lack of source and cap rocks, whereas the retrogradational and progradational framework limestone usually occurs in the later sequences (S2 and S4-S5) of the supersequence, which results in two perfect sets of source, reservoir and cap rock assemblies, so that the limestone in sub-member C2-C4 and the F-Member can be predicted as important objects for oil exploration.

The study of hydrocarbon origin,transport and accumulation in tazhong area,tarim basin

Abstract: The exploration of Tarim marine facies layer system developed quickly recent yearsThere are great discoveries at NoI Faulted Slope Break in Tazhong area,especially the Upper Ordovician carbonate reef complexThe study finds that the Upper Ordovician carbonate reef complex has several stages of oil and gas migrate accumulation,including the accumulation,adjustment and transforming of Late Caledonian,also the oil supplement from hydrocarbon of Late Hercynian,the air cutting of paleo-oil hydrocarbon cracking to the early oil reservoirThe crude oil and condensate oil mainly came from Cambrian-Lower Ordovician,and the oil and gas mainly came from vertical and lateral the transformation through several reservoirThe Ordovician reservoir is condensate oil in outer belt and oil in inner belt,the reason is the gas was came from the cracking of paleo-oil of the underlying Cambrian-lower Ordovician and the northern NoI Faulted Slope Break and migrate upward along the NoI Faulted Slope Break,then accumulated in the reef complex reservoir,which caused the gas invasion to the previous oil reservoirThe different degrees of gas invasion induced the condensed reservoir and oil reservoir

A Reservoir-scale Miocene Injectite near Santa Cruz, California

Abstract: The Yellow Bank creek complex (YBCC) is a large, upper Miocene injectite complex, one of numerous injectites northwest of Santa Cruz, California. The feeder for these injectites is the Santa Margarita Sandstone, a shelfal sandstone unit that is also the reservoir rock in several exhumed oil fields. The impermeable cap rock for these oil fields, the Santa Cruz Mudstone, was breached by sand injectites, some of which reached the sea floor. Located near the edge of one of these oil fields, the YBCC is a dike-sill complex that shows evidence for multiple phases of injection by fluidized sand that was initially gas or water saturated and later possibly oil bearing. Vertical injection of a large sand dike along a fracture was followed by lateral injection of a sill from the dike along bedding planes in the Santa Cruz Mudstone. Flow differentiation during injection of fluidized sand into the sill formed centimeter-scale layering in its lower part. Subsequent emplacement of oil into this sand may have occurred by injection and by seepage that displaced pore water, producing sand masses that became preferentially cemented by dolomite. Some evidence suggests that the injection and cementation occurred at relatively shallow burial depths beneath the sea floor, with the injection resulting from a combination of possible seismic shaking and migration of overpressured fluids from more deeply buried parts of the Santa Margarita Sandstone. A pervasive lamination marked by limonite staining developed following uplift and subaerial exposure of the complex, possibly in a groundwater environment.

The controlling factors and distribution prediction of H2S formation in marine carbonate gas reservoir, China

Abstract: Generally, there are some anhydrites in carbonate reservoir, as H2S is also familiar in carbonate oil and gas reservoirs. Nowadays, natural gas with high H2S concentration is usually considered as TSR origin, so there is close relationship between H2S and anhydrite. On the contrary, some carbonate rocks with anhydrite do not contain H2S. Recently, researches show that H2S is only a necessary condition of H2S formation. The reservoir porosity, sulfate ion content within formation water, reservoir temperature, oil/gas and water interface, hydrocarbon and some elements of reservoir rock have great controlling effects on the TSR occurrence. TSR deoxidizes hydrocarbon into the acidic gas such as H2S and CO2, and the H2S formation is controlled by TSR occurrence, so the relationship among reaction room, the contact chance of sulfate ion and hydrocarbon, the reservoir temperature has great influence on the TSR reaction. H2S has relatively active chemical quality, so it is still controlled by the content of heavy metal ion. Good conditions of TSR reaction and H2S preservation are the prerequisite of H2S distribution prediction. This paper builds a predictive model based on the characteristic of natural gas reservoir with high H2S-bearing. In the porosity reservoir with anhydrite, the formation water is rich in sulfate and poor in heavy metal ion. Oil and gas fill and accumulate in the gas reservoir with good preservation conditions, and they suffered high temperature later, which indicates the profitable area of natural gas with high H2S-bearing.

Mapping and classifying flow units in the upper part of the mid-cretaceous sarvak formation (western dezful embayment, sw iran) based on a detemination of reservoir rock types

Abstract: The mid-Cretaceous Sarvak Formation, the second-most important reservoir unit in Iran, is composed mainly of grain-supported carbonates. For the purposes of this study, flow units in the upper part of the formation were identified, mapped and classified as part of an integrated reservoir characterization study at a giant oilfield in SW Iran. Pore types and geometries, pore-scale diagenetic history and core-scale depositional attributes were logged using conventional petrographic and lithological methods. The resulting data were combined with core descriptions, mercury-injection capillary pressure data, and wireline log and geophysical data to identify five reservoir rock types: (i) highly oil-stained, grain-supported carbonates, including patch reef and barrier complex deposits with high porosities and permeabilities; (ii) leeward and seaward shoal deposits including grain-supported packstones and skeletal wackestones with high porosities and permeabilities; (iii) dominantly mud-supported lagoonal and open-marine facies with fair porosity and permeability; (iv) grain-supported but highly cemented facies which had poor reservoir characteristics; and (v) calcareous shales and shaly limestones with no reservoir quality. Based on the reservoir rock types, eight flow units were recognised. Subsequently, four reservoir zones were defined based on these flow units at a field scale. This study has contributed to our understanding of flow units in this complex carbonate reservoir, and has improved our ability to characterize and model the architecture of the reservoir from pore to core to field scale.

Diagenesis of Triassic Feixianguan Formation in Sichuan Basin,Southwest China

Abstract: The proved reserves of sour gas pools were up to 1×1012 m3 from oolitic dolostone reservoirs of Feixianguan Formation in northeast Sichuan Basin,that are mainly distributed in the sedimentary sequence with evaporites.Remnant gypsum and anhydrite,their moidic pores or molds in the reservoirs indicate that the dolomitization was related to the evaporated seawater.Furthermore,in some diagenesis sequence of the reservoirs,the dolomitization extent increases with depth from ancient subaerial exposure surface downwards.This implies that the dolomitization of the oolitic limestone took place in the early stage of diagenesis,and was possibly influenced by mixing rain water and evaporated seawater. For δ13C and δ18O values between structural constituents of the oolitic dolomite in the reservoirs,the difference is great,so the values of intermix sample of reservoir rock are not suited for dolomitization research. In the reservoirs,the most oolitic dolostone preserved the remainder of oolitic fabric or original rock framework,the various pores of the dolostone are almost secondary dissolved pores and not shrinkage pores due to dolomite crystals shrink.The replacement process of dolomitization is a volume replacement for volume,not a mole for mole.The relationship between bitumen and secondary dissolved pores indicates that late burial dissolution pores are dominant in the reservoirs. The ionization constant of H2CO3 is much higher than that of H2S in the solution,whereas the mole of CO2 is much lower than that of H2S in the sour gas of Feixianguan Formation.The late period calcite cement,filled in the dissolved pores and fractures of the oolitic dolomite reservoirs,is characterized by low δ13C(-18‰) and high homogenization temperature(130~180℃),so the CO2,related to thermochemical sulfate reduction in the reservoirs,causes mainly late burial dissolution.

Upper Cretaceous Microbial Petroleum Systems in North-Central Montana

Abstract: Cenomanian to Campanian rocks of north-central Montana contain shallow economic accumulations of dry natural gas derived from microbial methanogenesis. The methanogens utilized carbon dioxide derived from organic matter in the marginal marine sediments and hydrogen from in situ pore water to generate methane. The most recent USGS assessment of the shallow gas resources of eastern Montana used a petroleum systems approach, identifying the critical components of a petroleum system (source rock, reservoir rock, seal rock, and trap) and their temporal relationships. As a part of this effort, geochemical data from natural gas wells and associated formation waters were used to identify two microbial gas systems and the timing of methanogenesis. Two microbial gas families are identified in north-central Montana based on stable carbon isotope and gas composition. The Montana Group gas family has heavier δ13C methane values, slightly lighter δD methane values, and a lower carbon dioxide and nitrogen content than the Colorado Group gas family. The two gas families may reflect, in part, the source rock depositional environments, with the Colorado Group rocks representing a more offshore marine depositional environment and the Montana Group rocks representing proximal marine, deltaic and nonmarine depositional environments. Assuming the gas families reflect only source rock characteristics, two microbial petroleum systems can be defined. The first petroleum system, called the Colorado Group microbial gas system, consists of Colorado Group rocks with the shales in the Belle Fourche Formation, Greenhorn Formation, and the Carlile Shale as the presumed source rocks and the interbedded Phillips and Bowdoin sandstones and the Greenhorn Formation limestones as reservoirs. The second petroleum system, called the Montana Group microbial gas system, consists of the Montana Group rocks that include the Gammon Shale and possibly the Claggett Shale as source rocks and the Eagle Sandstone and the Judith River Formation as reservoirs. The Niobrara Formation is tentatively placed in the former system. The geographic extent of the two microbial systems is much larger than the study area and includes an area at least from the Alberta basin to the northwest to the Powder River basin to the southeast. Upper Cretaceous microbial gas accumulations have been recognized along these basin margins at burial depths less than 3000 ft, but have not been recognized within the deeper parts of the basins because subsequent charge of thermogenic oil and gas masks the preexisting microbial gas accumulations. Methanogenesis began soon after the deposition (early-stage methanogenesis) of the Cenomanian to Campanian source sediments, and was either sustained or rejuvenated by episodic meteoric water influx until sometime in the Paleogene. Methanogenesis probably continued until CO2 and hydrogen were depleted or the pore size was compacted to below tolerance levels of the methanogens. The composition of the Montana and Colorado Group gases and coproduced formation water precludes a scenario of late-stage methanogenesis like the Antrim gas system in the Michigan basin. Some portion of the methane charge was originally dissolved in the pore waters, and subsequent reduction in hydrostatic pressure caused the methane to exsolve and migrate into local stratigraphic and structural traps. The critical moment of the microbial gas systems is this timing of exsolution rather than the time of generation (methanogenesis). Other studies suggest that the reduction in hydrostatic pressure may have been caused by multiple geologic events including the lowering of sea level in the Late Cretaceous, and subsequent uplift and erosion events, the youngest of which began about 5 Ma.

Diagenesis of Triassic Feixianguan Formation in Sichuan Basin, Southwest China

Abstract: The proved reserves of sour gas pools were up to 1×1012 m3 from oolitic dolostone reservoirs of Feixianguan Formation in northeast Sichuan Basin，that are mainly distributed in the sedimentary sequence with evaporites. Remnant gypsum and anhydrite , their moidic pores or molds in the reservoirs indicate that the dolomitization was related to the evaporated seawater. Furthermore, in some diagenesis sequence of the reservoirs, the dolomitization extent increases with depth from ancient subaerial exposure surface downwards. This implies that the dolomitization of the oolitic limestone took place in the early stage of diagenesis，and was possibly influenced by mixing rain water and evaporated seawater.  For δ13C and δ18O values between structural constituents of the oolitic dolomite in the reservoirs, the difference is great, so the values of intermix sample of reservoir rock are not suited for dolomitization research. In the reservoirs , the most oolitic dolostone preserved the remainder of oolitic fabric or original rock framework , the various pores of the dolostone are almost secondary dissolved pores and not shrinkage pores due to dolomite crystals shrink. The replacement process of dolomitization is a volume replacement for volume, not a mole for mole. The relationship between bitumen and secondary dissolved pores indicates that late burial dissolution pores are dominant in the reservoirs .  The ionization constant of H2CO3 is much higher than that of H2S in the solution ,whereas the mole of CO2 is much lower than that of H2S in the sour gas of Feixianguan Formation. The late period calcite cement ，filled in the dissolved pores and fractures of the oolitic dolomite reservoirs， is characterized by low δ13C (-18‰) and high homogenization temperature (130~180℃), so the CO2,related to thermochemical sulfate reduction in the reservoirs , causes mainly late burial dissolution.

System and method for evaluating petroleum reservoir using forward modeling

Abstract: This invention relates to petroleum reservoir characterization. It uses a novel system and method to generate a system of reservoir models, and then use a series of simulation techniques to simulate the models. The models are refined through each simulation and comparison step by comparing the results of the simulation with the known data from the reservoir. The invention can be applied to different reservoirs which have different known properties. Simulation techniques such as EM test forward calculation, stochastic reservoir modeling, streamline forward calculation are all candidates of simulation methods disclosed in the invention.

Fans Sedimentation and Exploration Direction of Fan Hydrocarbon Reservoirs in Foreland Thrust Belt of the Northwestern Junggar Basin

Abstract: The Permian-Jurassic alluvial-fan,subaqua-fan,fan delta were well occured and widely distributed in foreland fold-and-thrust belt of the northwest Junggar basin Synsedimentary faults acting in varied period strictly controlled sedimentation and distribution of various fans from Permian to Jurassic The fan bodies formed at P_1j and P_3w have the largest distribution and scale The Permian was characterized by a model of forward thrusting movement of synsedimentary controlling-fan faults and obvious gradual advance migration response of fan bodies from the margin to the center of Junggar basin The fan bodies formed at T_1b and T_2k own the largest distribution and scale from T_1b to J_2t stage Triassic-Jurassic was characterized a model of shrink back thrusting migration of controlling-fan faults and gradual countermarch migration response of fan bodies from the center to the edge of Junggar basinKnown fan petroleum pools mainly enrich in four subfacies belt(root-middle part of underwater fan and alluvial fan, fan delta plain-front), as well as six horizons(P_1j、P_ 2-3 w、T_1b、T_2k、J_1b、J_2t) Permian-Triassic fans have plenty of oil-bearing formation, large scale of petroleum pool, higher reserves abundance But Jurassic fans went in opposite conditions Fan bodies mainly formed fault block oil reservoir, stratigraphic unconformity oil pools, structural-lithological oil pools, lithological pools which are concerned with faults and unconformity Structural pools mainly distribute at scalariform fault belt and root-middle part of fans, lithological pools mainly forms at slope belt and middle-front of fans The main controlling factors of petroleum pool forming are trusting fault, unconformity, lithofacies and physical nature of fans There were the pool-forming pattern of vertical migration-accumulation with the setup of fans and thrusting faults at scalariform fault belt; and the pool-forming pattern of lateral migration-accumulation with the combination of fans and unconformity at slope belt The pool-forming condition of fan boides was favorable, its prove extent was lower, and residual resources potential was great Then the seven beneficial exploration domains and favorable blocks in future are pointed out in foreland thrust belt of the northwest Junggar basin

Characteristics of petroleum accumulation in syncline of the Songliao basin and discussion on its accumulation mechanism

Abstract: The relation between oil and water in reservoirs with low and ultra-low permeability is very complicated. Gravitational separation of oil and water is not obvious. Normal reservoirs are located in depression and structural high spot, oil and water transitions are located in their middle. Stagnation is the key fact of oil-forming reservoir in the axis of a syncline based on the research of oil, gas and water migration manner, dynamics and non-Darcy flow in the Songliao basin. In low and ultra-low permeable reservoir, gas and water migrate easily through pore throats because their molecules are generally smaller than the pore throats; but the minimum diameter of oil droplets is larger than pore throats and they must be deformed to go through. Thus, gas and water migrate in advance of oil, and oil droplets remain behind. Pressure differential and the buoyancy force in a syncline reservoir are a main fluid driving force; and capillary force is the main resistance to flow. When the dynamics force is less than resistance, oil is immobile. When the buoyancy force is less than the capillary force, a gravitational separation of oil and water does not occur. The reservoir in the mature source rock of a syncline area with the low and ultra-low permeability belongs to an unconventional petroleum reservoir.

Water Saturation in Tight Gas Reservoirs

Abstract: Assuming a non-equilibrium scenario most of the nonconventional properties of gas-tight reservoirs are fully explained. The model is able to describe, among others, the following typical characteristics of these reservoirs: over-pressurization, “abnormal” low water saturation, unusually small or undetectable capillary transition zones, abnormal pressure gradients, reservoir to reservoir disconnection and absence of identifiable free water level. After accepting de usual over-pressurization as a direct indication of absence of hydrostatic equilibrium, the usual upscaling of capillary pressure curves results meaningless. It is so because capillary pressure was not originated in hydrostatic columns but in over-pressurization occurred when hydrocarbons were expulsed from the source rock (usually in close contact with reservoir rock). As a result, fluids distribution is affected by nonhydrostatic equilibrium conditions still acting at the time of reservoir discovery. A specially designed laboratory routine to measure the water saturation and electric properties directly on cores avoiding the usual water column modeling through capillary pressure curves, is presented. The relative permeability curves validity is also discussed.

A low frequency, passive seismic experiment over a carbonate reservoir in Abu Dhabi

Abstract: Alow frequency passive seismic experiment was conducted over an onshore carbonate oilfield in Abu Dhabi in an effort to confirm and understand the origins of a low frequency signal that has been observed above several hydrocarbon reservoirs in the area. While the analyses of the data are still on-going the preliminary results of the experiment have confirmed the existence of a narrow band of low frequency (2.5-2.8 Hz) signals over the oil reservoir zone; however, this analysis has found that these signals are also detected over the water saturated zone. More studies will need to be conducted to fully investigate the particle motion of these waves, their apparent velocities, and the azimuth of their wave fronts. Background For the past several years a narrow band of low frequency (1.5 – 4 Hz) signals have been observed and reported over a number of hydrocarbon reservoirs mainly in the Middle East including some oilfields in Abu Dhabi (Dangel et al., 2003; Holzner et al., 2005). The observations suggest that the low frequency signature diminishes towards the rim of the reservoir and is absent above non-reservoir locations. It has been suggested that these signals are caused by non-linear behaviour of the interaction between liquid hydrocarbons, water, and the pore-rock materials in the reservoirs which distort the normal signature of the Earth’s natural ambient vibration spectra. The analyses of such low frequency data have previously been used as a direct hydrocarbon indicator for the optimization of well placement during exploration, appraisal, and production. However, the possible causes of this low frequency energy are not well understood and it has yet to be demonstrated what types of waves are being observed as well as the physical behaviour of the multiphase fluid system in the reservoir. Furthermore, to date most of these observations have only been based on the vertical component of the signal motion. As a result, this experiment aims to better understand the wave systems causing these observations by systematically mapping the temporal and spatial variations of the low frequency waves recorded. The results of this passive seismic experiment will help to determine the source of such low frequency energy and its possible application in the detection and monitoring of hydrocarbons in carbonate reservoirs. The processing and modelling of the data from the experiment are still on-going; hence, the aim of this short paper is to present the preliminary results of the experiment.

Method of deposition phase control for casting sandstone oil reservoir attribute

Abstract: A method of utilizing sedimentary facies control to predict attribute of sandstone oil deposit reservoir includes digitalizing sedimentary facies belt, predicting reservoir parameter between sedimentary facies wells and describing mutual action feature of sedimentary facies control stone-fluid based on studying result of relativity between sedimentary microfacies and reservoir sandstone attribute.