Showing papers on "Petroleum reservoir published in 1990"

A Practical Model for Organic Richness from Porosity and Resistivity Logs

Abstract: A practical method, the delta log R technique, for identifying and calculating total organic carbon in organic-rich rocks has been developed using well logs. The method employs the overlaying of a properly scaled porosity log (generally the sonic transit time curve) on a resistivity curve (preferably from a deep-reading tool). In water-saturated, organic-lean rocks, the two curves parallel each other and can be overlain, since both curves respond to variations in formation porosity; however, in either hydrocarbon reservoir rocks or organic-rich non-reservoir rocks, a separation between the curves occurs. Using the gamma-ray curve, reservoir intervals can be identified and eliminated from the analysis. The separation in organic-rich intervals results from two effects: the orosity curve responds to the presence of low-density, low-velocity kerogen, and the resistivity curve responds to the formation fluid. In an immature organic-rich rock, where no hydrocarbons have been generated, the observed curve separation is due solely to the porosity curve response. In mature source rocks, in addition to the porosity curve response, the resistivity increases because of the presence of generated hydrocarbons. The magnitude of the curve separation in non-reservoirs is calibrated to total organic carbon and maturity, and allows for depth profiling of organic richness in the absence of sample data. This method allows organic richness to be accurately assessed in a wide variety of lithologies and maturities using common well logs.

Relationship between diagenesis and reservoir quality in sandstones of the Garn Formation, Haltenbanken, mid-Norwegian continental shelf

Abstract: A quantitative model is proposed for the dependence of porosity and permeability on diagenesis in subarkosic arenites of the Middle Jurassic Garn Formation. Porosity variation is controlled by the combined effects of compaction and quartz cementation. In general, more porosity has been lost by compaction than by quartz cementation, but compactional porosity loss appears to have occurred relatively early in the burial history (before burial below 2 km below the sea floor). Thus, progressive reduction of the total porosity with increasing burial below 2 km results mainly from quartz cementation. Permeability is a function of the abundance of intergranular macroporosity, which is interpreted to be a measure of "effective porosity." At depths less than 3.5 km below the sea fl or, intergranular macroporosity generally comprises more than 50 percent of the total porosity, but at greater depth, as total porosity decreases below about 16 percent, the ratio of effective to ineffective porosity drops below one. This depth corresponds to the onset of extensive illitization and grain dissolution, which results in major reorganization of the pore system. Generation of secondary porosity by feldspar dissolution appears not to have been beneficial to reservoir quality in the Garn Formation, but it is regarded as an intrinsic part of the overall process of porosity destruction with increasing diagenesis.

Petroleum Migration in the Miocene Monterey Formation, California, USA: Constraints from Fluid-Inclusion Studies

Abstract: The Miocene Monterey Formation constitutes a fracture-controlled petroleum reservoir, with intercalated calcareous and fine-grained siliceous rocks serving as both the source and reservoir for oil accumulations. Petroleum is produced from macroscopic fractures, and numerous tar and asphalt seeps at the surface attest to the present-day movement of hydrocarbons through fractures in the Monterey Formation. Many fractures are filled with carbonate (mostly calcite and dolomite), quartz, baryte and anhydrite. These same fractures often contain tar or oil filling openings, and occasionally a thin layer of oil can be seen coating growth surfaces between two generations of vein-filling minerals. Evidence for migration of fluids through these fractures in the geological past is provided by aqueous and petroleum fluid inclusions contained within vein-filling minerals. Vein-filling dolomite from Jalama Beach contains three different types of primary petroleum inclusions (based on fluorescence characteristics)—indicating that oils with significantly different API gravities flowed through the fractures. Petrographic and microthermometric analyses of oil and coexisting aqueous inclusions indicate that the fracture-filling minerals precipitated from aqueous solutions of seawater salinity at ∼75–100°C, and that oil was introduced into the fracture system episodically during mineral growth. A sample from the Lion's Head area consists of early calcite and late quartz, both of which contain aqueous inclusions with seawater salinity. Inclusions in quartz homogenize at slightly higher temperatures than those in calcite. These data are consistent with calcite deposition during an early heating event, followed by quartz deposition during cooling. No petroleum inclusions were observed in the Lion's Head sample.

Sulfuric acid speleogenesis of Carlsbad Cavern and its relationship to hydrocarbons, Delaware Basin, New Mexico and Texas

Abstract: Sulfur-isotope data and pH-dependence of the mineral endellite support the hypothesis that Carlsbad Cavern and other caves in the Guadalupe Mountains were dissolved primarily by sulfuric acid rather than by carbonic acid. Floor gypsum deposits up to 10 m thick and native sulfur in the caves are significantly enriched in {32}S; (isotope){34}S values as low as -25.8 per mil (CDT) indicate that the cave sulfur and gypsum are the end products of microbial reactions associated with hydrocarbons. A model for a genetic connection between hydrocarbons in the basin and caves in the Guadalupe Mountains is proposed. As the Guadalupe Mountains were uplifted during the late Pliocene-Pleistocene, oil and gas moved updip in the basin. The gas reacted with sulfate anions derived from dissolution of the Castile anhydrite to form H[2]S, CO[2], and "castile" limestone. The hydrogen sulfide rose into the Capitan reef along joints, forereef carbonate beds, or Bell Canyon siliciclastic beds and there reacted with oxygenated groundwater to form sulfuric acid and Carlsbad Cavern. A sulfuric-acid mode of dissolution may be responsible for large-scale porosity of some Delaware basin reservoirs and for oil-field karst reservoirs in other petroleum basins of the world.

Rock/fluid interactions of carbonated brines in a sandstone reservoir: Pembina Cardium, Alberta, Canada

Abstract: When CO{sub 2} is injected into petroleum reservoirs it forms carbonic acid in the brine phase and interacts with reservoir rock. Flow tests were performed by continuously circulating CO{sub 2}-saturated brines through Cardium formation cores. All the cores initially showed a large drop in permeability. after which permeability rose steadily but did not regain its initial value. Microscopic examination of the cores indicates that fines had been released and had migrated toward pore throats, reducing permeability, In addition, mineral alterations occurred, including the dissolution of calcite and siderite, which may account for the gradual rise in permeabilities noted in the experiments.

Formation evaluation 2

Abstract: This book reports on: interpretation methods, shaly sand reservoirs, fractured reservoirs, reservoir temperature and source rock evaluation. The papers presented include: fracture detection with logs and Temperature surveys in gas producing wells.

Geology and Diagenetic History of Overpressured Sandstone Reservoirs, Venture Gas Field, Offshore Nova Scotia, Canada

Abstract: Deep exploratory wells in the Scotian Basin, offshore Nova Scotia, Canada, have encountered overpressured formations with pressures 1.9 X the normal hydrostatic gradient. The overpressures occur over an area of approximately 10,000 sq km. In the Venture field, the abnormal pressures are confined below a depth of 4500 m and are associated with Upper Jurassic-Lower Cretaceous gas- and condensate-bearing sandstone reservoirs. The overpressures occur within normally compacted shales containing numerous overpressured sandstone reservoir beds. The development of overpressures, seals, and secondary reservoirs are all diagenetically driven. The volumetric increase achieved by kerogen to petroleum-gas conversion and hydrocarbon expulsion are believed to be the main driving forces or Venture overpressures. Three secondary porosity depth levels, which top at 2500 m (65 degrees C), 3700 m (95 degrees C), and 4600 m (130 degrees C), correlate with major steps in the organic matter maturation in the basin. Secondary porosity is initially achieved by alumosilicate dissolution, with ferroan sparry calcite cement dissolution dominating below 4000 m. Porosity enhancement and preservation is not the result of a single diagenetic event but instead the result of a series of diagenetic events that overlapped in time. Formation of dynamic diagenetic barriers within the zone of peak gas generation helps retard the diffusive migration of hydrocarbons and other fluids expelled during shale diagenesis resulting in pressure build up. The preservation of up to 32 percent porosity under 500-1000 atm of pressure could not be achieved without simultaneous pressuring of developing voids. Thus, the expansion of secondary reservoirs in the overpressured zone also had to be late (50 Ma or younger) and about synchronous with pressurizing of the reservoirs. Significant for hydrocarbon exploration is that Venture-type diagenetic overpressures are not associated with undercompacted sediments and, hence, they cannot be predicted from compaction trends during drilling. Petrographic, diagenetic, and lithofacies studies can be instrumental in predicting potential areas of deep subsurface secondary reservoirs development.

Characterization of non-Darcy multiphase flow in petroleum bearing formations

Abstract: The objectives of this research are: Develop a proper theoretical model for characterizing non-Darcy multi-phase flow in petroleum bearing formations. Develop an experimental technique for measuring non-Darcy flow coefficients under multiphase flow at insitu reservoir conditions. Develop dimensional consistent correlations to express the non-Darcy flow coefficient as a function of rock and fluid properties for consolidated and unconsolidated porous media. The research accomplished during the period May 1991--May 1992 focused upon theoretical and experimental studies of multiphase non-Darcy flow in porous media.

A new type of reservoir rock in volcaniclastic sequences

Abstract: Development of pronounced secondary porosity and permeability, accompanied by dramatic changes in wave propagation velocity and other physical properties, in laumontite tuffs occurs in the oil fields of eastern Georgia, Soviet Union. These rocks originated during intense hydrothermal alterations of andesite tuffs and comprise local (few meters thick), commonly lens-shaped bodies. Hydrothermal alteration was lithologically and structurally controlled, resulting in the formation of specific reservoir rocks identifiable on geophysical logs and capable of producing oil and gas. The considerable relief of the in-situ stress within these bodies was estimated from differential velocity analysis using sonic-log and laboratory data. This stress relief, as well as borehole enlargem nts (accompanied by the development of zones of nonelastic deformation around the hole) tends to enhance near-well permeability and, hence, the productive potential of these uncommon and poorly studied reservoirs.

Sandstone petroleum reservoirs

Abstract: Sandstone Petroleum Reservoirs presents an integrated, multidisciplinary approach to the geology of sandstone oil and gas reservoirs. Twenty-two case studies involving a variety of depositional settings, tectonic provinces, and burial/diagenetic histories emphasize depositional controls on reservoir architecture, petrophysical properties, and production performance. An introductory section provides perspective to the nature of reservoir characterization and highlights the important questions that future studies need to address. A "reservoir summary" following each case study aids the reader in gaining quick access to the main characteristics of each reservoir. This casebook is heavily illustrated, and most data have not been previously published. The intended audience comprises a broad range of practicing earth scientists, including petroleum geologists, geophysicists, and engineers. Readers will value the integration of geological versus engineering interests provided here, and will be enabled to improve exploration and production results.

The neogene-quaternary section in the nile delta, egypt: geology and hydrocarbon potential

Abstract: The Nile Delta area covers nearly 60,000 sq. kms in the northern part of Egypt. The Nile Delta basin contains a thick sequence of Neogene-Quaternary clastics that are considered to be prospective for oil and gas. The information available for investigating the basin sediments, and evaluating their hydrocarbon potential, has been gathered from some 24 wells. As most of these wells have not penetrated below the Miocene, deeper sediments could not be investigated. The studied section is uniform across the northern Delta, consisting of at least 15,000 ft. of shales and sandstones, it becomes thinner southwards. The section is composed of three sedimentary cycles, including eight formations. Thick, organic-rich sediments were deposited under favourable conditions for oil and gas genesis in several parts of the studied basin. The northern part of the onshore area, and the eastern and western parts of the offshore area, are favourable sites for hydrocarbon generation and accumulation for the following important reasons: (1) mature source rocks, (2) structural relief capable of trapping hydrocarbons in the eastern and western parts of the offshore area (Abu Qir and El-Temsah localities), (3) stratigraphic traps in the northern part of the onshore area, and (4) the depositional features of the Abu Madi Formation.

Thermo-Chronological Approach to Reservoir Diagenesis in the Offshore Angola Basin: a Fluid Inclusion, {40}Ar-{39}Ar and K-Ar Investigation (1)

Abstract: Microthermometric analyses of fluid inclusions and geochronological surveys of authigenic silicates in Neocomian sandstones and Albian dolomitic reservoirs from the offshore Angola basin have allowed determination of the age and the physical-chemical conditions for fluid migration in a late diagenetic stage. The {40}Ar-{39}Ar laser probe dating of adularia overgrowths from the Albian reservoirs shows that the trapping of primary aqueous and oil inclusions occurred during the early Miocene (25.6 + or - 3.2 Ma). The K-Ar age of authigenic illites from the Neocomian sandstones is slightly younger (19 + or - 1 Ma), and the crystallization of regular illite-smectite mixed layers is related to a previous Eocene to Paleocene diagenetic stage (51-58 Ma). There appears to have bee both a regional and vertical variation in the salinity of aqueous fluids during the Miocene. The fluid inclusion trapping temperatures were estimated by correcting the homogenization temperatures of aqueous fluids, assuming that pressures during the Miocene were close to the present reservoir pressures, and by intersecting the isochores of aqueous and oil inclusions, assuming they were trapped at strictly similar pressure and temperature conditions. The fluid inclusion temperatures are consistent with those derived from the tetrahedral aluminum content (AlIV) of authigenic chlorites: 168-206 degrees C in the Albian reservoirs at depths between 2350 and 3580 m, and 175-237 degrees C in the Neocomian sandstones at depths between 2770 and 4470 m. In both reservoir formations, Miocene tempe atures were higher than the present ones and related either to deeper burial or higher geothermal gradient.

Description of natural fracture systems for quantitative use in petroleum geology

Abstract: We present a method for estimating fracture porosity and permeability from measurements of fractures in small samples of a fracture system. A fracture system is divided into domains from which samples are collected. Lengths, widths, and numbers of fractures present in samples are measured and then summarized in density and distribution functions. These raw data, in turn, are combined using Monte Carlo techniques to estimate fracture porosities and permeabilities for domains and to develop their respective density and distribution functions. Finally, estimates from domains can be displayed in maps and cross sections to characterize the spatial variation of fracture porosity and permeability throughout the fracture system. We have evaluated this procedure through comparison with estimates of fracture porosity and permeability reported in the literature and with data from three fractured reservoirs. Comparison with values reported in the literature indicates that the method yields the proper range, form of distribution function, and representative values for fracture porosity. Application of the method to specific reservoirs indicates the difficulties of estimating fracture porosity by any means. These applications also indicate, however, that very poor quality fractured reservoirs (i.e., with fracture porosities much less than 0.1%) can be recognized from core and that estimates of fracture porosity for viable fractured reservoirs through the use of core may be somewhat low. In contrast, estimates of fr cture permeabilities of samples, although not unreasonable as estimates for individual samples, are larger than those typically obtained by reservoir engineering methods for fractured reservoirs. In part, these differences may be diminished by fully including in the method reductions due to in-situ stresses and fracture fill. In part, however, the differences must be due to the conceptual difference between permeability of samples and gross permeability of fractured reservoirs.

Secondary migration routes in the Brent sandstones of the Viking graben and east Shetland basin: Evidence from oil residues and subsurface pressure data

Abstract: The Viking (Graben of the North Sea contains a major deltaic reservoir-the Brent Group. Within the Brent Group, the Etive Formation, a coastal barrier sand, is both areally continuous and has excellent porosity and permeability. It is sandwiched between the fine-grained micaceous sandstones of the Rannoch Formation below and the impermeable mudstones of the Ness Formation above. Consequently, the Etive Formation has acted as the most important regional conduit for secondary migration of Upper Jurassic sourced oils. Oil migration through time has left a heavy residue in the uppermost part of the formation. These residues are aromatic-asphaltic, but otherwise resemble locally reservoired oils. Migration-sensitive biological marker ratios obtained from the residues change wi h distance from source. Secondary migration route mapping, based on the movement of oil by buoyancy in well-defined, isolated pressure compartments, integrated with timing of oil generation, indicates that the Ninian field could be sourced from two areas-Late Cretaceous migration from the southeast in the Viking Graben and Tertiary migration from the west and southwest-explaining some of the contrasting reservoir and oil characteristics of the Ninian and Lyell fields.

Oil-source rock correlation using carbon isotope data and biological marker compounds, Cook Inlet-Alaska Peninsula, Alaska

Abstract: Rock and oil samples from the Cook Inlet-Alaska Peninsula area were analyzed to determine the source of the commercial hydrocarbons produced in the Cook Inlet basin from lower Tertiary nonmarine sandstone reservoirs. Rock-Eval (hydrogen index) analysis and organic carbon content were used to identify the most favorable rock samples for solvent extraction and carbon isotope, gas-chromatographic (GC), and gas-chromatrographic/mass-spectrometric (GCMS) analyses. On the basis of organic-matter richness, five nonmarine Tertiary coal and shale samples and 12 marine Mesozoic (Upper Triassic and Middle Jurassic) shale samples were selected. A total of 28 oil and condensate samples from producing wells, oil-stem tests, field separators, and seeps were used for oil-oil and oil-source rock correlation. On the basis of biomarker and carbon isotope data, four of the shallower oils and condensates are from nonmarine source rocks, and 24 of the deeper oils are sourced from marine shales. Geochemical and regional geologic considerations indicate the following conclusions. The upper Tertiary nonmarine oils and condensates associated with commercial microbial gas accumulations are geochemically similar to the immature organic matter in the Tertiary nonmarine rocks. In the upper Cook Inlet, marine oils in lower Tertiary nonmarine reservoirs originated from Middle Jurassic rocks that matured during themore » Pliocene to Holocene; in the lower Cook Inlet-Alaska Peninsula area, oils migrated from both Upper Triassic and Middle Jurassic source rocks during the Late Cretaceous to early Tertiary. Although three petroleum systems are identified, this study on the petroleum potential in a convergent-margin setting indicates that only one of these three systems was responsible for the 1.2 billion bbl of recoverable oil in the lower Tertiary nonmarine reservoirs.« less

Method of determining fracture parameters for heterogenous formations

Abstract: A method of determining fracture parameters for heterogeneous formations is provided based upon pressure decline measurements from minifrac tests. The inventions provide methods for generating type curves for heterogeneous formations, as well as a leak-off exponent that characterizes specific fracturing fluid/formation systems.

Fluvial Architecture and Reservoir Compartmentalization in the Oligocene Middle Frio Formation, South Texas

Abstract: Seeligson, Stratton, and Agua Dulce fields (South Texas) are being studied as part of a Gas Research Institute/Department of Energy/State of Texas cosponsored program designed to develop and test methodologies and technologies for gas reserve growth in conventional reservoirs in mature gas fields. Over the last five decades, each field has produced approximately 2 Tcf of gas from middle Frio reservoirs alone. Recent drilling, old-well workover results, and reservoir pressure data, however, point to the possibility of additional reserves within these fields. The middle Frio (Oligocene) is composed of sand-rich channel-fill and splay deposits interstratified with floodplain mudstones, all forming part of the Gueydan fluvial system. Channel-fill deposits are 30 ft (9 m) thick and 2,500 ft (76 m) wide. Splay deposits are as much as 20 ft (6 m) thick proximal to channels and extend as much as 2 mi (3 km) from channels. Channel-fill and associated splay sandstones are reservoir facies (porosity = 20 percent; permeability = 10's to 100's md); floodplain mudstones and levee sandy mudstones impede or obstruct flow and separate individual reservoirs and compartments both vertically and laterally. Deposition on an aggrading coastal plain resulted in a continuum of fluvial architectural styles that has important implications for reservoir compartmentalization. Relatively slow aggradation resulted in laterally stacked channel systems, whereas more rapid aggradation resulted in vertically stacked channel systems. In Seeligson field, laterally stacked architecture alternates with vertically stacked architecture through the 2,000-ft- (610-m-) thick middle Frio section. In Stratton and Agua Dulce fields, the same general alternation in architectural modes exists through the 2,500-ft- (763-m-) thick middle Frio section. In Stratton and Agua Dulce, however, the reservoir zones composed of laterally stacked architecture are not laterally continuous; instead, the laterally stacked architecture locally changes into a vertically stacked architecture. Because laterally stacked sandstone bodies lead to separate but potentially "leaky" reservoir compartments and vertically stacked sandstone bodies favor more "isolated" reservoir compartments, a high potential for reserve growth through the identification of untapped, poorly drained, and bypassed gas reservoir compartments exists in each of these fields. Differences in reservoir architecture also must be taken into account as part of exploitation strategies.

Porosity prediction, prior to drilling, in sandstones of the Kekiktuk Formation (Mississippian), North Slope of Alaska

Abstract: Porosity in sandstones of the Kekiktuk Formation was successfully estimated prior to drilling of the 1 Leffingwell wildcat well (North Slope of Alaska). The estimate was based on a calibration dataset used to evaluate the effects of (1) framework grain composition, (2) depositional facies, and (3) postdepositional processes on porosity of Kekiktuk sandstones. The sandstones of the Kekiktuk Formation are chert-bearing sublitharenites and quartzarenites characterized by a homogeneous composition of the detrital framework in the study area. Thus, mineral composition is not a major factor responsible for differences in reservoir quality. Based on outcrop and available core observations, the Kekiktuk Formation was interpreted to include several wet fan-deltas. The depositional model suggested that the 1 Leffingwell well would penetrate the distal, fine-grained facies of one such system. A petrographic study indicated that in fine- and very fine-grained Kekiktuk sandstones, such as those predicted in the wildcat, porosity was reduced primarily by silica cementation. Silica cementation, in turn, is related to burial history. Because of the relationship among porosity, silica cementation, and burial history, burial history diagrams provided a measure of the effect of burial history on porosity in available calibration wells. A synthetic burial history curve was constructed prior to drilling of the 1 Leffingwell well from available seismic data. This burial history curve was then used to estimate the well's porosity based on the previously established porosity-burial history relationship.

Regional Diagenetic Variation in Norphlet Sandstone: Implications for Reservoir Quality and the Origin of Porosity

Abstract: Although deeply buried (18,000 -> 20,000 feet) eolian and reworked marine Norphlet arkose and subarkose in Mississippi, Alabama, and Florida have been intensely studied by several workers, fundamental questions remain regarding diagenetic controls on reservoir quality and the origin of porosity. In spite of a regionally uniform framework composition of quartz, albite, and potassium feldspar, the diagenetic character of the unit is variable on a scale ranging from individual laminations to single hydrocarbon-producing fields to areas encompassing several fields or offshore blocks. The presence or absence of clay minerals in various forms clearly is a dominant control on porosity-permeability trends. In deep reservoirs in Mobile Bay and offshore Alabama and Florida petrographic evidence for dissolution of pervasive authigenic carbonate and/or evaporite minerals to produce high secondary porosity values is equivocal or absent. Although evidence exists for some secondary porosity, much porosity appears to be relict primary porosity. On a regional scale, including both onshore and offshore areas, sandstones with radial, authigenic chlorite coats consistently have high porosity and permeability. In Mobile Bay and offshore Alabama, the distribution of this form of chlorite may be controlled by the presence of precursor clay/iron-oxide grain coats. The occurrence of these coats likely is related to environment of deposition. For example, reworked marine sands, which constitute much of the "tight zone" in the upper Norphlet in Mobile Bay and offshore Alabama, were deposited in an environment hostile to formation or preservation of syndepositional grain coats, as also may have been the case in some subenvironments of the eolian system. Although chlorite is the dominant authigenic clay mineral in offshore areas, illite is dominant in onshore areas. Sandstones with authigenic illite fibers and flakes typically have permeability values lower, by an order of magnitude or more, than those with authigenic chlorite. In general, chlorite is dominant in eastern areas of Norphlet exploration and production and illite is dominant in western areas. It is unlikely that provenance variations are of sufficient magnitude to account for the distribution of the two clay minerals, particularly since illite or chlorite may dominate in different wells within the same onshore field. Variations in types of authigenic carbonate minerals and in degree and type of feldspar alteration suggest that differences in fluid composition and fluid-flow paths relative to sub-basins, structural highs, salt structures, fault systems, and depositional texture are important. The occurrence of authigenic magnesium-rich chlorite, zeolites, and an unusual ferroan magnesite cement indicates that fluids associated with evaporites and variations in the composition of evaporites or residual fluids may be responsible for variation in diagenetic character of the Norphlet. Evaporites associated with these fluids include the underlying Louann salt and evaporite systems within the Norphlet.

In situ stress and natural fracture distribution in the Ekofisk Field, North Sea

Abstract: In situ stress and natural fractures have been mapped across the structural dome that forms the Ekofisk field in the Norwegian sector of the North Sea. The reservoir rock is chalk and a natural fracture system forms the primary conductive path for produced hydrocarbons and injected fluids. In situ stress measurements have been made using hydraulic fractures and anelastic strain recovery measurements of oriented core. 36 refs., 21 figs., 2 tabs.

Estimating organic maturity from well logs, Upper Cretaceous Austin Chalk, Texas Gulf coast

Abstract: The Austin Chalk is both a source rock for oil and a fractured reservoir, and the evaluation of its organic maturity from well logs could be an aid to exploration and production. Geochemical and core measurements have shown three zones of organic maturity for source materials: (1) an immature zone above 6000 ft, (2) a peak-generation and accumulation zone from 6000 to 7000 ft, and (3) a mature, expulsion and migration zone below 7000 ft. The response of common well logs identifies these zones. True resistivity (Rt) is low in the immature zone, increases to a maximum in the accumulation zone, and decreases to intermediate values in the migration zone. Density and neutron porosities are different in the immature zone but are nearly equal in the accumulation and migration zones. Correlations with conventional core analyses indicate that Rt values between 9 and 40 ohm-m in the migration zone reflect a moveable oil saturation of 10% to 20% in the rock matrix. The moveable saturation provides oil from the matrix to fractures and is essential for sustained oil production. Therefore, the log evaluation of moveable oil could be important in exploration.

Interaction of cold-water aquifers with exploited reservoirs of the Cerro Prieto geothermal system

Abstract: Cerro Prieto geothermal reservoirs tend to exhibit good hydraulic communication with adjacent cool groundwater aquifers. Under natural state conditions the hot fluids mix with the surrounding colder waters along the margins of the geothermal system, or discharge to shallow levels by flowing up fault L. In response to exploitation reservoir pressures decrease, leading to changes in the fluid flow pattern in the system and to groundwater influx. The various Cerro Prieto reservoirs have responded differently to production, showing localized near-well or generalized boiling, depending on their access to cool-water recharge. Significant cooling by dilution with groundwater has only been observed in wells located near the edges of the field. In general, entry of cool water at Cerro Prieto is beneficial because it tends to maintain reservoir pressures, restrict boiling, and lengthen the life and productivity of wells. 15 refs., 10 figs., 1 tab.

Injection-Water Quality

Abstract: Ideally, injection water should enter the reservoir free of suspended solids or oil. It should also be compatible with the reservoir rock and fluids and would be sterile and nonscaling. This paper discusses how the objective of any water-injection operation is to inject water into the reservoir rock without plugging or permeability reduction from particulates, dispersed oil, scale formation, bacterial growth, or clay swelling. In addition, souring of sweet reservoirs by sulfate-reducing bacteria should be prevented if possible.

Application of sterane epimerization to evaluation of Yoshii gas and condensate reservoir, Niigata Basin, Japan

Abstract: A practical method is used to assess maturation histories and paleotemperatures of mudstones. This method is based on 20R-C[29] sterane epimerization and the apparent heating rate. A relationship among sterane epimerization, maximum burial temperature, and heating rate is determined assuming kinetic constants of sterane epimerization. This relationship is used to reconstruct the subsidence and thermal histories of mudstones and accumulated oils in the young Nishiyama/Chuo oil field (Tertiary-Quaternary). The estimated thickness of eroded sediments in the Haizume/Uonuma Formation, the uppermost rocks in the Nishiyama/Chuo oil field, indicate subsidence and heating rates of 2-4 km/m.y. and 80-160 degrees C/m.y., respectively, and uplift and cooling rates of 2-4 km/m.y. and 80-160 degrees C/m.y., respectively, during the late Quaternary. These rates suggest recent vigorous tectonism in the Niigata back-arc sedimentary basin. Based on geologic observations and maturation levels of crude oils, the oil generation threshold and primary migration stage correspond to degrees of sterane epimerization of 20S/(20S + 20R) = 0.20 to 0.35 and 20S/(20S + 20R) = 0.40 to 0.50, respectively. The anticlinal structure of Yoshii gas and condensate reservoir was formed prior to the late Pliocene. The therma and subsidence histories of source rocks indicate that the accumulation of hydrocarbons in Yoshii reservoir rocks started in the Pleistocene. Further maturation of these reservoir rocks and the possible addition of gases from overmature source rocks during the late Quaternary resulted in formation of the Yoshii gas-condensate reservoir. Formation of anticlinal structure of Nishiyama reservoir began in the late Quaternary after the major stage of oil migration. Vigorous tectonism during the late Quaternary caused abrupt development of the anticline, allowing oil to accumulate to form Nishiyama reservoir.

Reservoir Characterization and Diagenesis of the Oligocene 64-Zone Sandstone, North Belridge Field, Kern County, California

Abstract: The Oligocene (Zemorrian) 64-Zone sandstone is an important oil and gas reservoir in North Belridge field, Kern County, California. The 64-Zone is a submarine-fan deposit that ranges from 83 to 137 m in thickness. Although diagenesis has played an important role in modifying porosity and permeability, the overall variations in reservoir quality reflect an upward increase in grain size associated with depositional processes. Three diagenetic events have had a significant impact on reservoir quality: (1) compaction, which has reduced intergranular volume to an average of 20%, (2) quartz cement, which has reduced porosity by an average of 6.2%, and (3) feldspar dissolution. Although an average of 2.7% porosity is directly associated with leached feldspar grains, mass balance calculations indicate that secondary porosity is roughly balanced by formation of authigenic kaolinite, resulting in little or no net gain in porosity. Three episodes of calcite cementation reflect various stages of burial history. Petrographic and isotopic data demonstrate that calcite I formed at shallow depths in the zone of bacterial sulfate reduction. Fluid inclusion data indicate that calcite II precipitated at temperatures of 92 to 167°C from fluids less saline than seawater. Fracture-filling calcite III postdates calcite II, but formed at lower temperatures (85 to 125°C). The results of isotopic modeling indicate that calcite II precipitated in equilibrium with waters expelled by shales during I/S diagenesis (^dgr18OSMOW = +2 to +8^pmil) and that calcite III precipitated during tectonic uplift from a mixture of shale-derived and meteoric waters (^dgr18OSMOW = 0 to +4^pmil) Most fluid inclusions in calcite II yield temperatures greater than present bottom-hole values (^sim110°C). Assuming that fluid inclusions in calcite II record maximum burial and a geothermal gradient of 33°C/km, tectonic uplift of 0.6 to 1.7 km (^sim2000-5700 ft) would be required to explain the fluid inclusion data.

Hydrocarbon distribution in Tertiary sandstones as a function of formation pressure and temperature

Abstract: Hydrocarbon distribution is related to formation pressure and temperature, with the highest concentrations of all hydrocarbons encountered near the onset of abnormal pressure regimes. A thorough understanding of the interactive relationship between lithology, pressure, temperature, and hydrocarbon distribution is essential for the efficient exploration and development of oil and gas accumulations. All information, such as lithology, pore pressure, and temperature, can be obtained from geophysical well logs. The primary purpose of this presentation is to discuss distribution and redistribution of hydrocarbons in Tertiary sandstones of southern Louisiana with respect to the depth pressure, and temperature at which these oil and gas accumulations are predominantly encountered. Also discussed are the thermodynamics of ascending fluid movement and the sourcing of these hydrocarbons. Production data from approximately 33,000 well completions and pressure/temperature data from over 20,000 wells provide the database used in this analysis. In addition, similar findings are presented for clastic overpressured reservoirs in the Baram Delta, located offshore in Sarawak Malaysia and the hydrocarbon resources being developed in the West Turkmen depression of the Soviet Union.

Porosity Prediction in Sandstones Using Erosional Unconformities

Abstract: Erosional unconformities of subaerial origin are created by tectonic uplifts and eustatic sea-level falls. Porosity increases below most erosional unconformities developed on sandstones, because uplifted sandstones are exposed to undersaturated CO2-charged meteoric waters, resulting in dissolution of unstable framework grains and cements. The chemical weathering of sandstones is intensified in humid regions by the heavy rainfall, soil zones, lush vegetation, and the accompanying voluminous production of organic and inorganic acids. Erosional unconformities are considered hydrologically and geochemically "open" systems because of the abundant supply of fresh meteoric water and relatively unrestricted transport of dissolved constituents away from the site of diss lution, causing a net gain in porosity near unconformities. Consequently, porosity in sandstones tends to increase toward overlying unconformities. Such porosity trends have been observed in hydrocarbon-bearing sandstone reservoirs in Alaska, Algeria, Australia, China, Libya, the Netherlands, Norwegian North Sea, Norwegian Sea, and Texas. A common attribute of these reservoirs is that they were all subaerially exposed under warm and heavy rainfall conditions. An empirical model has been developed for the Triassic and Jurassic sandstone reservoirs in the Norwegian North Sea on the basis of the observed relationship that shows an increase in porosity in these reservoirs with increasing proximity to the overlying Base-Cretaceous unconformity. An important practical attribute of this model is its capability of predicting porosity in the neighboring undrilled areas by recognizing the Base-Cretaceous unconformity in seismic reflection profiles and by constructing subcrop maps of stratigraphic units susceptible to porosity formation by meteoric waters. Caution must be exercised in developing predictive models using unconformities, because porosity reduction due to cementation may also occur beneath some erosional unconformities.

The geology and petroleum potential of the western arafura sea

Abstract: The northern Bonaparte Basin and the Arafura-Money Shoal Basins lie along Australia's offshore northern margin and offer significantly different exploration prospects resulting from their differing tectonic and burial histories. The Arafura Basin is dominated by a deep, faulted and folded, NW-SE orientated Palaeozoic graben overlain by the relatively flat-lying Jurassic-Tertiary Money Shoal Basin. The north-eastern Bonaparte Basin is dominated by the deep NE-SW orientated Malita Graben with mainly Jurassic to Recent basin-fill. A variety of potential structural and stratigraphic traps occur in the region especially associated with the grabens. They include tilted or horst fault blocks and large compressional, drape and rollover anticlines. Some inversion and possibly interference anticlines result from late Cenozoic collision between the Australian plate and Timor and the Banda Arc. In the Arafura-Money Shoal Basins, good petroleum source rocks occur in the Cambrian, Carboniferous and Jurassic-Cretaceous sequences although maturation is biassed towards early graben development. Jurassic-Neocomian sandstones have the best reservoir potential, Carboniferous clastics offer moderate prospects, and Palaeozoic carbonates require porosity enhancement. The Malita Graben probably contains good potential Jurassic source rocks which commenced generation in the Late Cretaceous. Deep burial in the graben has decreased porosity of the Jurassic-Neocomian sandstones significantly but potential reservoirs may occur on the shallower flanks. The region is sparsely explored and no commercial discoveries exist. However, oil and gas indications are common in a variety of Palaeozoic and Mesozoic sequences and structural settings. These provide sufficient encouragement for a new round of exploration.