Lateral Oil Migration Research Articles

Regional unconformities and their controls on hydrocarbon accumulation in Sichuan Basin, SW China

Based on outcrop, seismic and drilling data, the main regional unconformities in the Sichuan Basin and their controls on hydrocarbon accumulation were systematically studied. Three findings are obtained. First, six regional stratigraphic unconformities are mainly developed in the Sichuan Basin, from the bottom up, which are between pre-Sinian and Sinian, between Sinian and Cambrian, between pre-Permian and Permian, between middle and upper Permian, between middle and upper Triassic, and between Triassic and Jurassic. Especially, 16 of 21 conventional (and tight) gas fields discovered are believed to have formed in relation to regional unconformities. Second, regional unconformity mainly controls hydrocarbon accumulation from five aspects: (1) The porosity and permeability of reservoirs under the unconformity are improved through weathering crust karstification to form large-scale karst reservoirs; (2) Good source-reservoir-caprock assemblage can form near the unconformity, which provides a basis for forming large gas field; (3) Regional unconformity may lead to stratigraphic pinch-out and rugged ancient landform, giving rise to a large area of stratigraphic and lithologic trap groups; (4) Regional unconformity provides a dominant channel for lateral migration of oil and gas; and (5) Regional unconformity is conducive to large-scale accumulation of oil and gas. Third, the areas related to regional unconformities are the exploration focus of large gas fields in the Sichuan Basin. The pre-Sinian is found with source rocks, reservoir rocks and other favorable conditions for the formation of large gas fields, and presents a large exploration potential. Thus, it is expected to be an important strategic replacement.

Migration directions of crude oils from multiple source rock intervals based on biomarkers: A case study of Neogene reservoirs in the Bodong Sag, Bohai Bay Basin

Identifying oil origins and reconstructing oil migration directions are vital for oil exploration in continental petroliferous basins, but they become difficult and complicated when multiple source rock intervals are encountered. This is the case of the Neogene fluvial reservoirs in the Bodong Sag, Bohai Bay Basin, east China, which show significant spatial heterogeneity in oil charging. Here, we take the LK9-2 Structure in the southeastern Bodong Sag as an example to determine the potential factors controlling the oil migration directions from multiple source rock intervals. Total organic carbon contents, Rock-Eval pyrolysis results and biomarkers were applied to distinguish the major oil sources and trace the oil migration pathways. The first–second and third members of the Eocene Shahejie Formation and the third member of the Oligocene Dongying Formation in the Bodong Sag all showed high potential of generating oils for the overlying Neogene reservoirs. However, oil–source correlation by biomarkers revealed that the Neogene oils of the LK9-2 Structure were mainly derived from the third member of the Dongying Formation. Oils generated from the underlying Shahejie Formation were, however, mostly blocked by the thick mudstones of the Dongying Formation. The dimethyldibenzothiophenes and benzo[b]naphthothiophenes parameters, indicative of oil migration directions, showed the failure of lateral oil migration within the Neogene reservoir layers, which had been cut by active shallow normal faults. Therefore, the uppermost thick source rock intervals and abundant active shallow normal faults in the way of lateral oil migration were the two major factors that controlled the oil migration directions from multiple source rock intervals and probably accounted for the many uncharged traps in the Bodong Sag.

Combining Geological Conditions and Geochemical Techniques to Analyze the Controlling Effect of Lateral Migration Paths of Sand Bodies on Reservoir Distribution

The lateral migration of oil and gas in the sandstone transport layer is continuously distributed, which is controlled by the distribution of the oil and gas potential energy field in the formation. The parameter ratio traces the migration path of oil and gas in the sandstone transport layer, and the results show that the lateral migration of oil and gas in the sand body is mainly concentrated in the vicinity of the paleostructural ridge and the dominant migration channel.

Oil Charging Power Simulation and Tight Oil Formation of Fuyu Oil Layer in Sanzhao Area, Songliao Basin

A thermodynamic and hydrocarbon composition model based on VTFlinc software was conducted based on the homogenization temperature of fluid inclusions and gas-to-liquid ratio, and the fluid inclusions’ trapped pressure was calculated. This software does not require the determination of individual inclusions, the composition of the simulation procedure is simple, and the simulation result has certain reliability. The VTFlinc software was used to calculate the trapped pressure of oil inclusions in the Fuyu tight reservoir of the Sanzhao area in the Songliao Basin. The results show the existence of two phases of oil charge. The first phase occurred at the end of the Nenjiang Formation at 79–74 Ma with an oil entrapped pressure of 16.922–19.068 MPa, and pressure coefficient of 1.18–1.26. During the second period in the Sifangtai Mingshui group at 69–64 Ma, the oil entrapped pressure was 20.216–28.830 MPa, and the pressure coefficient was 1.21–1.33. During the two periods, the pressure of the trapped oil inclusions is abnormal, and the pressure coefficient is above 1.2. Abnormal high pressure is the main driving force of hydrocarbon source rock and oil in the Fuyu Formation, as well as an important driving force for the lateral migration of oil in the tight reservoir. The reservoir formation model of the Fuyu tight oil reservoir in the Sanzhao area is a direct high-pressure charging and multi-channel migration accumulation model. The Q-1 source rock and Fuyu oil layer has a direct contact relationship between the source rock and the reservoir.

Особливості забруднення ґрунтів нафтою та нафтопродуктами: огляд

Soil pollution is inevitable in course of oil extraction, transporting, storage, refining and usage of oil products. The affected soils lose their initial value and spread pollutants into the environment: air, ground- and surface waters, food chains. Effective environmental protection is impossible without reliable information about the state of polluted soil. An understanding of changes, which undergoes soil after oil (oil products) ingress, its ecological evaluation gives an opportunity to determine the state of the soil ecosystem and to select remediation measures, effective under given natural conditions. The article elucidates the influence of various oil fractions on the morphological, physical, physicochemical and chemical properties of soils. The regularities of vertical and lateral oil migration through the soil were considered. The oil pollution resilience of different types of soils was also presented. The reaction of live organisms: germs, mesofauna, algoflora and plants on the influence of oil pollution was highlighted. An important aspect is a generalization of approaches towards the evaluation of the ecological state of oil- and oilproduct- polluted soil because the threshold limit values of oil and the products of its refining in the soil are not established in Ukrainian legislation. Our overview showed that multicomponent oil contamination, its temporal transformation, cumulative properties, high stability and toxicity, variability of hydrocarbon contents, absence of the threshold limit values for most oil products, inability to take into account the ecological hazard of joint action of hydrocarbons, products of their decomposition and interaction with other substances, present in water and soil, require complex approach towards solution of the problem. The first important stage of it is the integral evaluation of the ecological state of the soil.

Prediction of favorable areas for oil accumulation in outer-source tight reservoirs under the control of lateral migration distance: A case study of the Baikouquan Formation, Mahu Sag, Junggar Basin, China

There is a starting pressure gradient (SPG) for oil migration in tight reservoirs (TRs), and the SPG and the migration force jointly control the migration distance of oil. The key factor of oil accumulation in the tight glutenite reservoir (TGR) of the Lower Triassic Baikouquan Formation (T1 b) in the Mahu Sag is whether the oil can be laterally charged into the TRs. To analyze the lateral migration distances of oil in TRs and predict the favorable accumulation areas for oil, we have carried out a physical simulation experiment of oil charging on glutenite reservoirs of T1 b for obtaining the SPG of oil migration and knowing the relationship between SPGs and the reservoirs’ physical property. According to the basin simulation, we have obtained the pressure evolution of the source-rock formation as well as reservoir formation and the physical property evolution of the reservoir. Finally, we have predicated the favorable oil accumulation areas through calculating the distribution characteristics of SPGs as well as the theoretical distances of lateral migration of oil during the key oil accumulation period and considering the theoretical distance of the lateral migration of oil as the main controlling factor. Our results suggest that there is a SPG in the TGR of the T1 b and that there is a power function relationship between the SPG and the permeability. The theoretical lateral migration distance of oil in T1 b during the key oil accumulation period was the farthest in the northern sag, which was gradually shortened to the east, west, and south. In class I favorable areas, the reservoirs have good physical properties where overpressure has developed; in addition, the lateral migration distance of oil is far. Therefore, these are the most favorable areas for oil accumulation.

Natural fracture propping and earthquake-induced oil migration in fractured basement reservoirs

Abstract The geological processes that create fluid storage capacity and connectivity in global fractured basement reservoirs are poorly understood compared to conventional hydrocarbon plays. Hosting potentially multibillion barrels of oil, the upfaulted Precambrian basement of the Rona Ridge, offshore west of Shetland, UK, gives key insights into how such reservoirs form. Oil presence is everywhere associated with sub-millimeter- to meter-thickness mineralized fracture systems cutting both basement and local preseal cover sequences. Mineral textures and fluid inclusion geothermometry suggest a low-temperature (90–220 °C), near-surface hydrothermal system, as does the preservation of clastic sediments in the same fractures. These fills act as permanent props holding fractures open, forming long-term fissures in the basement that permit oil ingress and storage. Calcite-fill U-Pb dating constrains the onset of mineralization and contemporaneous oil charge to the Late Cretaceous. The additional preservation of oil-stained injected sediment slurries and silica gels along basement faults suggests that rift-related seismogenic faulting initiated lateral oil migration from Jurassic source rocks into the adjacent upfaulted ridge. Subsidence below sea level in the latest Cretaceous sealed the ridge with shales, and buoyancy-driven migration of oil into the preexisting propped fracture systems continued long after the cessation of rifting. These new observations provide an explanation for the viability of sub-unconformity fractured basement reservoirs worldwide, and have wider implications for subsurface fluid migration processes generally.

Evaluations of oil and gas lateral migration across faults: A case study of Shigezhuang nose structure of Wen'an slope in Baxian sag, Jizhong depression, Bohai Bay Basin, East China

Abstract To study the possibility and location of lateral migration of oil and gas across faults, a quantitative evaluation method for lateral migration of oil and gas across faults was established using the Shuangjing Knipe graphic method to identify the juxtaposition site and juxtaposition patterns of sand and sand in the upper and lower walls of the reverse faults and the consequent faults, combined with the oil and gas limit method of fault lateral seal in the test oil area. The quantitative evaluation method was applied to the first and two members of the Paleogene Shahejie strata (referred to as Es1 and Es2) of Shigezhuang nose structure of Wen'an slope in Baxian sag, Jizhong depression, Bohai Bay Basin, to determine the juxtaposition site of sand and sand in the upper and lower walls of the fault, and the shale gouge ratio (SGR) lower values are 26% and 29% respectively in the strata Es1 and Es2. Thus, the location of lateral migration of oil and gas across faults was determined. Based on the oil and gas distribution characteristics of the strata Es1 and Es2, and variation trend of nitrogen compounds in 4 wells in the strata Es1, the results were consistent with the quantitative evaluation of the location of lateral migration of oil and gas across faults, the feasibility of the evaluation method was preliminarily verified.

Oil origin and accumulation in the Paleozoic Chepaizi–Xinguang field, Junggar Basin, China

The Chepaizi–Xinguang area is a petroliferous region in the western Junggar basin that contains several Permian tight reservoirs and has a complex petroleum system and accumulation mechanism. The oil sources and accumulation mechanisms are investigated by an integrated analysis of biomarker assemblages in reservoir oil samples, microscopic analysis of rock samples, study of fluid inclusions, and simulation of the thermal evolution. The results show that the Permian oil in the Xinguang bulge is mainly generated from the Permian Fengcheng Formation with tricyclic terpane ratios C19 TT/C23 TT lower than 0.15, C23 TT/C21 TT higher than 1.0 and gammacerane/αβ C30 hopane higher than 0.6. The Permian oil in the Chepaizi area is mostly derived from Permian Wuerhe Formation with C19 TT/C23 TT higher than 0.15, C23 TT/C21 TT lower than 1.0 and gammacerane/αβ C30 hopane lower than 0.4. The Permian oils from the Xinguang bulge show higher maturity compared to the Permian oils from the Chepaizi area possibly as a result of later oil filling. The fluid inclusions and fluorescence record the main oil charging movements during the Late Triassic to Early Jurassic and the Late Jurassic to Early Cretaceous in this area, and most of the generated oils in late Permian are lost. The unconformities between Permian strata show higher porosity and more oil and gas enrichment comparatively and are the main pathways for lateral oil migration. Laumontite has had a considerable effect on reservoir properties. Laumontite dissolution creates pores that provide good oil reservoir space and favorable exploration targets.

High-pressure visual experimental studies of oil-in-water dispersion droplet size

The formation of oil-in-water dispersions is a critical step during the blowout of coastal and deepwater oil and gas production systems, and is a determining factor in the vertical and lateral migration of oil through the associated adjacent water column. In this study a high-pressure sapphire visual autoclave apparatus was used to measure the size of crude oil droplets that were saturated with gas and dispersed in an aqueous phase as a function of mixing speed. Oil-in-water droplet size distributions were measured at pressures of 11MPa, for autoclave stirring rates of 200–1000RPM (1076≤Restirred vessel≤5378). Arithmetic mean droplet diameters decreased monotonically from 344 to 125μm over this range, with maximum droplet sizes decreasing from 708 to 441μm. A model tuned to the measured oil-in-water data was used to predict a mean droplet size on the order of 80μm for Deepwater Horizon conditions; when incorporated into far field blowout simulations, this droplet size data enables quantitative assessment of the impact of dispersant injection at the blowout site.

Paleofluid analysis from fracture-fill cements in the Asmari limestones of the Kuh-I-Mond field, SW Zagros, Iran

Kuh-I-Mond field in the Zagros foreland basin is a conventional heavy oil resource and is composed of fractured carbonates whose fractures were filled by calcite, dolomite, and anhydrite cements. Oil inclusions occurred within the fracture-fill cements indicate that fractures were open and played an active role during oil migration and charge. The highest measured values for secondary porosities belong to fractures in Asmari Formation, which is characterized by significant amounts of vug- and fracture-filling cements. Fractures facilitated fluid circulation and subsequently dissolution of allochems and high Mg carbonates. In contrast, fine-grained carbonate facies were less cemented, and thus, porosity enhancement by cement dissolution was insignificant. Temperature profiles of oil inclusions in the dolomite, calcite, and anhydrite minerals characterized by distinct variations in the homogenization temperatures (Th) that are divided into two ranges below 50°C in anhydrites and from 45°C to 125°C in dolomites and calcites. The lower Th ranges for anhydrite suggests that it may have formed at shallower burial depths during early to middle diagenesis. The oil inclusions display trend for increasing temperature downward which conform to Formation geothermal gradient. In other word, the decreasing trend of Th temperatures upward within Asmari Formation that can be observed in Th versus depth plot is consistent with the uplift events at Late Miocene time and later that caused removal of about 1,300 m of the crest of the Kuh-I-Mond anticline. Vitrinite reflectance data from source rock intervals in the field area do not support vertical migration of locally generated hydrocarbons into the Kuh-I-Mond accumulation, and long-distance lateral oil migration and charge from a source kitchen to the southwest is proposed. Vitrinite reflectance data from this dolomite and limestone reservoir suggest low maturation levels corresponding to paleotemperatures less than 50°C. The observed maturation level (<0.5% Ro) does not exceed values for simple burial maturation based on the estimated burial history. Also, homogenization temperatures from fluid inclusion populations in calcite and dolomites show expected good correlation with reflectance-derived temperatures. The Th data represent pore fluids became warmer and more saline during burial. As aqueous fluid inclusions in calcite veins were homogenized between 22°C and 90°C with a decrease in salinity from 22 to 18 eq. wt.% NaCl. The Th values suggest a change in water composition and that dolomite and calcite cements might have precipitated from petroleum-derived fluids. The hydrocarbon fluid inclusions microthermometry data suggest that the reservoir was being filled by heavy black oils in reservoir during Cenozoic. Aqueous fluid inclusions hosted by calcite equant sparry/fossil cavity fills suggest low cementation temperatures (<45°C) and high salinities (19 eq. wt.% NaCl), while those in dolostones are characterized by highly variable homogenization temperature (52°C to 125°C) and salinities (6.5 to 20 eq. wt.% NaCl).

Spatial variation of Bakken or Lodgepole oils in the Canadian Williston Basin

There are two opposing schools of thought that infer either the Bakken Formation or the Lodgepole Formation as the primary source rock for the Madison-reservoired oils in the Canadian Williston Basin. A recent geochemical study revealed evidence indicating the existence of significant mixing of Bakken and Lodgepole oils in the Madison reservoirs. To investigate the geographic distribution of the oil compositions, we employed a multivariate statistical method to extract source and maturity-specific geochemical signatures from a geochemical data set for spatial analysis. Oil mixing appears to be geographically dependent and restricted by a northeast-southwest–striking zone (Torquay-Rocanville trend) in southeast Saskatchewan. Thus, fracture or fault systems are inferred to have provided high-permeability zones allowing Bakken-derived oil to migrate upward across the Lodgepole Formation. The areas without significant fault or fracture systems favor lateral oil migration along porous beds, restricting Bakken-derived oil accumulation to pools in Bakken reservoirs and Lodgepole-derived oils to occur primarily in overlying reservoir beds of the Madison Group.

Habitat of Biodegraded Heavy Oils: Industrial Implications

Heavy oil, extra-heavy oil and tar sands account for half of the petroleum resources of the world. Due to their high viscosity their production is a major technical and economical challenge. The understanding of the origin and geological habitat of these unconventional oils is crucial in order to optimize exploration and production operations. The vast majority of these heavy oils originates from the biodegradation of conventional oils by bacterial activity. The limiting factors of the involved biological processes (temperature, nutrients, etc.) are controlled by the geological situation. In this respect, foreland basins which harbour a large part of the current deposits of heavy oils correspond to particularly favourable conditions in promoting the biodegradation of large charges of oil. They are characterized by long distance lateral oil migration draining substantial volume of the petroleum system. This migration is supported by an adequate drainage system which exhibits a large lateral continuity and consists of the first syntectonic fluvial and fluvial-deltaic sediments filling the foreland basins. As a result of this migration the oil reaches shallow situation in the forebulge where the temperature is compatible with bacterial activity. The reservoirs associated with the “forebulge” are often high porosity and high permeability sand bodies, initially hosting large volume of water and facilitating the circulation of meteoric water helping in the nutrient availability. For the sake of production, the heterogeneities associated with these fluvial and fluvial-deltaic sediments have to be carefully considered. The geological models developed for the architecture and for the stratigraphic evolution of fluvial channels and incised valleys provide useful guidelines in order to characterize the reservoirs for production purposes in such geological setting. The technical difficulties in recovering these highly viscous fluids require to integrate more detailed reservoir description than usually needed when producing conventional oil plays. The Cretaceous reservoirs of the Mannville Formation in Canada is presented to exemplify the types of heterogeneities encountered in fluvial reservoirs, their rational, their effect on the heavy oil recovery and the impact of the geological knowledge on the production strategy.

A new method for identifying secondary oil migration pathways

A method called Oil Migration Intervals (OMI) is presented to assist identifying lateral oil migration pathways intersected inexploration boreholes. It predicts potential profiles of residual oil saturation due to partial confinement of oil below sealing strata using a pseudodisplacement pressure log and the buoyancy gradient. The OMI method performs calculations on wireline log data and uses empirical correlations between permeability and displacement pressure to derive a continuous pseudodisplacement pressure log for an intersection of reservoir or carrier bed. A pseudopermeability log is calculated from a modified Wyllie-Rose equation by replacing the irreducible water saturation factor with an empirical pore aperture parameter utilising V -Shale and Porosity. The pseudodisplacement pressure is subtracted from the buoyancy gradient to obtain profiles of potential excess buoyancy pressure and thus relative residual oil saturation due to partial confinement beneath sealing strata. The OMI log can then be directly compared with scaled field or laboratory measured oil show indicators to identify genuine secondary (lateral) oil migration. The steps in the calculation of the OMI log have been calibrated using laboratory and field data from exploration oil wells in the Timor Sea, NW Shelf, Australia.

Factors Controlling Simpson Group Production in Central Oklahoma

ABSTRACT The area of study includes Townships 7 through 9 North, Ranges 1 through 3 West, Cleveland and McClain Counties, Oklahoma. Sandstones of the five Simpson Group Formations have produced more than 65,000,000 barrels of oil from this 324 square mile area. Production is from structural traps, generally small faulted anticlines ranging in size from 80 to 750 acres. Cumulative oil production per field ranges from 36,000 to 11,760,000 barrels of oil. The distribution of oil production from within the Simpson Group has been considered enigmatic because, although all of the sandstone members are present throughout the study area, some fields have attained production from all of the sandstone members and others produce from only one horizon. The Simpson shales are not capable of generating hydrocarbons and the oil produced from the Simpson Group probably originated from the Devonian/Mississippian Woodford Shale. The McClain County fault juxtaposed the Woodford Shale with the Simpson Group enabling lateral oil migration from the Woodford into the Simpson sandstone. Also, tortuous migration pathways allowed Woodford oil to ultimately accumulate in Simpson reservoirs which involve downthrown younger rocks adjacent to upthrown older rocks. Slight structural movements occurred contemporaneously with the deposition of the Simpson Group creating semi-parallel northeast-southwest oriented thick and thin trends. Local structural movements were active during part or all of Simpson deposition. This created stratigraphic variations in the individual Simpson Group Formations which caused the apex of a field to migrate (or even vanish) with depth. Consequently, lower Simpson structures may not be reflected by upper Simpson structures, and conversely, upper Simpson structures may not continue with depth. Variations in Viola deposition enhanced the vertical discontinuity of structures within the study area so that mapped Viola structures may not reflect underlying Simpson structures. Furthermore, a dramatic change in the orientation of the structural grain began to appear in late Ordovician (Viola) time. Subsequent movements enhanced this later structural orientation producing two acute structural trends which control the entrapment of oil. This study demonstrates that the dual structural imprint is probably the single most important factor in controlling the distribution and accumulation of hydrocarbons within the area. The study also identified stratigraphic conditions within the Simpson Group sandstone which may affect their productivity.

On the Origin of the Gulf Coast Neogene Oils

ABSTRACT In the oil fields of the Bay Marchand-Caillou Island salt-ridge complex, Louisiana Gulf Coast, geometric considerations of oil location, extensive faulting associated with this ridge, and the compartmentalization of each oil reservoir all argue against updip lateral oil migration from a source south of the salt ridge, and suggest a local origin for the oils. However, an origin of the Caillou Island oils from shales interbedded with the oil-bearing sands is improbable because of: 1) the organ ic-poor nature of the shales, a characteristic of all Pleistocene through Oligocene shales in the Gulf Coast); 2) limited shale volume; 3) the low shale maturation rank; 4) primary migration considerations; and 5) compositional differences between shale bitumens and oils. The vertically-stacked oils at Caillou Island, and adjacent oil fields, comprise one genetically-related family, which is true for other vertically-stacked Neogene Gulf Coast oil fields. This genetic relationship suggests that the oils originated from a source, or sources, at depth. Three possible deep sources are proposed for the Neogene oils: 1) thick sections of moderately organic-rich (total organic carbon (TOC) = 2-5+%, hydrogen indices (HIs) = 300-450+) Eocene to Upper Cretaceous (or older) shales with hydrogen-rich (Type II) organic matter (OM); 2) Lower Cretaceous to Jurassic, organic-rich, black shales with high TOC and HIs, and Types I and II OM; and 3) Eocene to Paleocene hydrogen-rich coals and (or) carbonaceous shales. For any of these to be a source of the Neogene oils, hydrocarbon (HC) generation and migration must have occurred at maturation ranks at or above Ro = 1.35, the hypothesized thermal deadline for C15+ HCs. However, the three principal lines of evidence that support this deadline can be explained by other causes, and a large body of data contradicts this deadline. Consequently, this deadline is rejected here. A substantial data base from both nature and the laboratory suggests that different OM types may have different reaction kinetics due to different kerogen bond strengths, with Types I and II (hydrogen-rich) OM requiring higher maturation ranks for intense HC generation and migration than Types II-S and III OM. Persuasive lines of logic and evidence suggest that hydrogen-rich coals can be oil source rocks, and in other parts of the world it is taken for granted that they are. Thus, it is proposed here that the Gulf Coast Neogene oils may have originated from deeper, older, organic-rich rocks, from which the oils migrated vertically up major fault zones to be emplaced in shallower sandstones. Thus, faults are important elements in Gulf Coast HC exploration, and specific exploration targets can be predicted from this model.

GEOCHEMISTRY OF PETROLEUM MIGRATION DURING THE FORMATION OF KARAMAY OIL FIELD

The phenomena of geochemical migration during the formation of the Karamay Oil Field have been revealed by correlating the compositions of non-hydrocarbon, asphaltene, steranes and terpanes from between oils and rocks. The study on abnormal compaction observed in a deep well, which is located between the source area and the oil field, and the corresponding depletion of hydrocarbons further clarifies the conditions of the migration of oil and gas. Results show that the necessary condition for the formation of this giant oil field is a long distance of lateral migration of oil and gas followed by a redistribution along Ka.-Ur. large fault before accumulation in a large uplift.

THE DISTRIBUTION OF MAJOR OIL AND GAS RESERVES IN REGIONAL BASIN STRUCTURES – AN EXAMPLE FROM THE POWDER RIVER BASIN, WYOMING, USA

The location and geographic distribution of oil and gas reserves within a producing basin often indicate that a remarkable concentration of reserves has taken place in a small area. The concentration of reserves is the result of secondary hydrocarbon migration, itself governed by the basin‐wide regional structure which was present at the time of migration. These factors permit the definition of the most prospective areas of a new basin or play at an early stage in the exploration cycle. Basic geochemical data are required for the definition of critical details of the effective generative depocentre, and regional geological‐geophysical data are required to establish regional structures near particular source‐bed levels, or near top Basement as the deepest prospective level. Other data commonly utilized in the early stages of exploration, such as basin classification schemes, reservoir bed studies and tectonic analyses, are rather less important in forward basin evaluation.A particularly clear example of the importance of the regional basement structure in the concentration of oil reserves exists in the Powder River Basin, Wyoming, USA. Cumulative oil production here was over 1.9 B brls** in 1984 from more than 460 oilfields and pools. However, 1.5 B brls (79% of the basin output) were produced from only 22 fields (4.7% of the number of fields and pools in the basin). It is also remarkable that all 22 major oilfields in the Powder River Basin are located on positive Bouguer gravity anomalies, which are expressions of deep basement irregularities. Regional lateral oil migration in the Powder River Basin appears to have utilized routes resulting from Laramide deformation (Late Cretaceous ‐ Paleocene).The resultant basin structure was accentuated by regional structural‐topographic anomalies, which became sites of major structural and stratigraphic traps. In this case regional gravity maps seem to show sufficient details of the deep structure for the accurate definition of major exploration targets.The Powder River Basin is thus an excellent example of the importance of regional geological and geophysical reconnaissance data aimed at, and available for, the definition of major migration pathways at an early stage of hydrocarbon exploration. When combined with geochemical data, such an approach will become the basis for forward exploration in all known basins.

Altered rhyolites as oil and gas reservoirs in the Minaminagaoka gas field (Niigata Prefecture, Japan)

Subsurface geology and petrography of volcanic rocks of the recently discovered Minaminagaoka gas field show that good reservoirs in the field are altered rhyolites of the mid-Miocene Nanatani Formation. The Nanatani Formation is composed of mudstone, lava and pyroclastic rock with a composition of rhyolite, andesite and basalt. Rhyolites are divided into rhyolites A, B, B', C and D according to petrographical features. Rhyolite A is a hyaloclastite and pumiceous tuff of glassy rhyolite. Rhyolites B, B' and D are aphyric rhyolite lavas characterized by needle-like plagioclase in groundmass. Rhyolite C is perlite lava. Rhyolites B, D and C are suitable for reservoirs, whose pores are not primary, but are secondary macroscopic druses and micropores formed by hydrothermal alteration. Micropores are openings among crystal grains of quartz and albite and are several tens of micrometers in size. Alteration of rhyolitic rocks is of hydrothermal type and is characterized by a smectite (or smectite/chlorite mixed-layer mineral)-sericite-albite-quartz-carbonate mineral assemblage in the upper zone, but clay minerals in the lower zone are chlorite and sericite. Alteration of andesite and basalt is similar to that of rhyolite in general, but in the Kitafukazawa bore hole, andesite and basalt below 4640-m depth have chlorite-laumonite-prehnite-(pumpellyite-epidote) assemblage which is correlated to the assemblage of the higher part of the laumonite subfacies of zeolite facies. Formation temperature of secondary quartz, estimated by the measurement of the filling temperature of fluid inclusions, is ∼ 150°C and is nearly the same as the present temperature at the bottom of the hole. From the geological environment, characteristics of alteration and paleogeotherm, formation of rhyolite reservoirs and migration of oil and gas can be summarized as follows: (1) formation of volcanic piles by submarine volcanism of rhyolite, andesite and basalt, and deposition of mudstone around the piles; (2) generation of hydrocarbon in mudstone along with increasing temperature related to volcanism; and (3) formation of rhyolite reservoirs by hydrothermal alteration, followed by lateral migration of oil and gas into secondary pores.

Secondary lateral migration of oil in carbonate reservoirs

Secondary lateral migration of oil in carbonate reservoirs