Showing papers on "Petroleum reservoir published in 1984"

Geological Factors Influencing Reservoir Performance of the Hartzog Draw Field, Wyoming

Abstract: The Hartzog Draw field, a major sandstone oil reservoir in the Powder River basin of Wyoming, was discovered in 1975 and unitized in 1980. The field is under waterflood and is being considered for CO/sub 2/ miscible flooding. To aid in evaluating enhanced recovery, the working interest owners approved a comprehensive geological-engineering study using data from existing wells and new infill wells. Geologic facies identified in the study provided the stratigraphic basis for mapping reservoir flow units. These flow units more precisely describe variations in rock properties that control fluid flow. Within the flow units, bedding characteristics of the reservoir sandstones cause permeability anisotropy. Mineralogy and diagenesis affect permeability, porosity, water saturation, and sensitivity to injection fluids. The reservoir description resulting from this study provides insight into reservoir performance and forms the framework for reservoir engineering studies to predict waterflood and CO/sub 2/-flood recovery.

Atlas of Major Texas Oil Reservoirs

Abstract: This volume contains information on more than 1,828 reservoirs, with emphasis on 868 reservoirs that have cumulative gas production of greater than 30 billion cubic feet of natural gas. Texas gas reservoirs are classified into 73 plays, each of which is described in terms of its principal geologic and engineering production characteristics. This assessment of the similarities of gas occurrence within each play will assist in defining controls on gas accumulation, in identifying resources affected by new technology, and in expanding technology to maximize recovery through improved field development and production practices.

Middle Cretaceous Carbonate Reservoirs, Fahud Field and Northwestern Oman

Abstract: Reservoir facies in Fahud field and throughout northwestern Oman are in shallow-shelf carbonates of the middle Cretaceous Mishrif and Mauddud Formations. Interparticle porosity formed in the Mishrif as sand aprons of lithoclast and skeletal grainstones surrounding fault-block islands, and less commonly in the Mauddud as biostromes of rudist packstones. Moldic porosity after fine rudist debris is more common than interparticle porosity and occurs in thicker stratigraphic units, interpreted to have formed locally in meteoric-water lenses associated with islands, and regionally during subaerial exposure associated with sea level lows.

Efficiency of petroleum expulsion from shale source rocks

Abstract: The limited data available on the mechanism and the efficiency of the processes by which petroleum is expelled in the subsurface from source rocks into adjacent reservoir rocks are mostly qualitative1,2. We present here material balance-type comparisons of sample series extending from the centre portions of two adjacent hydrocarbon source rock units towards their outer edges3, which enable expulsion efficiencies to be determined. In certain parts of the shale the expulsion efficiencies for total extract and its saturated and aromatic hydrocarbon fractions, have much higher values than previously thought (reaching up to 80% for the total extract) which increase towards possible secondary migration avenues. The expulsion is associated with fractionation effects, such as those based on polarity differences. Also, expulsion efficiencies were found to be related to the degree of hydrocarbon saturation of the pore system: they are higher for a rich, oil-prone source rock unit compared with a poorer quality one, which had generated less hydrocarbons.

Dating diagenesis in a petroleum basin, a new fluid inclusion method

Abstract: The final porosity and permeability of sandstone petroleum reservoirs is greatly affected by the diagenetic growth of minerals after deposition. For example a sand may be deposited with a porosity of 25% and a permeability of 5,000 mdarcy (mD)1; diagenetic growth of quartz around detrital sand grains may leave a rock with only 10% porosity, and later growth of clays may partly fill these remaining pores and block inter-pore connections, reducing permeability to 100 mD (ref. 2). If the depth and timing of such diagenetic alteration can be measured and the extent of diagenesis estimated, then prediction of the diagenetic state of undrilled sandstones may become possible and diagenesis related more closely to the timing of hydrocarbon migration and the formation of hydrocarbon traps. We present an example of a new method for estimating the date of quartz diagenesis using a combination of techniques from thin section petrography, fluid inclusion thermometry, organic geochemical thermometry and sedimentary basin stratigraphic analysis. These results suggest that quartz in the Beatrice oilfield was precipitated from moving and cooling pore fluids, at a temperature between 68 °C and 94 °C in the late Jurassic.

Geochemical Exploration in the Powder River Basin

Abstract: Geochemical and geological data were used to identify effective source rocks and oil-types, and to determine stratigraphic sequences and areas that are prospective for crude oil and thermal hydrocarbon gas. The source rock volumes and generation-expulsion performance data for each effective source sequence provided the basis for calculating quantities of expelled oil and gas. These quantities readily account for discovered in-place reservoir oil of more than 7 billion barrels and relatively minor amounts of gas, mainly associated. Lower and Upper Cretaceous source beds expelled most of the indigenous oil. These oils are chemically similar, regardless of their source. Lower Cretaceous Mowry Shale and Upper Cretaceous Niobrara and Carlile formations expelled most of the discovered oil. Oil expulsion from Cretaceous source rocks began during the early Tertiary and continued through much of Miocene time as the expulsion fronts moved up section and updip. Laramide structure controlled directions of migration of Cretaceous oil. The second major type of oil is nonindigenous to the Powder River Basin and is correlated to the remote Upper Permian Phosphoria Formation source area centered in southeastern Idaho. This oil entered northeastern Wyoming during Late Jurassic time, before the Powder River Basin formed, through carrier beds of Pennsylvanian and Permian age. Phosphoria-type oil is preserved in four separate parts of the basin, primarily in sandstone reservoirs of Early Permian age in the Minnelusa and Tensleep formations. A minor oil-type found in the southeastern part of the Powder River Basin was expelled from relatively thin, local shales of Pennsylvanian age. Several giants fields with more than 100 million barrels of recoverable oil and major oil fields of at least 50 million barrels are located on structural positives around the periphery of the Powder River Basin. These salients served as gathering areas to concentrate migrating oil. Other large fields are in stratigraphic traps oriented parallel with structural strike on the eastern flank, this orientation permitting large accumulations to form from a big drainage area in downdip source rocks. Meteoric water, aerobic bacteria, distillation, and thermal cracking are affecting the quality of preserved oil. Two types of bacterial alteration are common. Much of the gas generated with oil has escaped or dispersed. Oxygenated recharge waters appear to be degrading organic matter in Cretaceous source rocks around the basin perimeter. Both chemical and physical properties of rocks and fluids proved to be useful in defining prospective areas for the various types of oil.

Lower Cretaceous Oil and Gas in Western Canada

Abstract: The Western Canada sedimentary basin contains tar deposits which exceed by three times the known recoverable oil reserves of the entire world. The tar was originally liquid oil which has been degraded by aerobic bacteria. It was generated principally from Lower Cretaceous but also from Jurassic and Triassic shales. The oil is contained in only 900 ft (275 m) of stratigraphic section above and below the Paleozoic unconformity. Oil migration paths were northeasterly, directly updip from the oil thermal window. The Athabasca anticline, a drape structure caused by Devonian salt removal, connects southward with the Sweetgrass Arch to form a 600-mi (965-km) long structural barrier on the eastern, updip rim of the basin. Most of the tar deposits are along the anticline or in a giant stratigraphic trap on the Paleozoic unconformity surface on the west flank of the anticline. There is no oil or gas east of the anticline. In the deepest part of the basin the Mesozoic section generated gas in comparably large volumes. Most of the gas has escaped to the outcrop, a small amount is contained in thousands of conventional stratigraphic pools on the east side, and an enormous volume is contained in tight sands on the west side, or the Deep basin. Most of the reservoirs are Lower Cretaceous sandstones. The tight, gas-saturated sands grade updip into porous water-saturated sands. The trap is not tightly sealed but leaks off at a steady rate. Continuing gas generation keeps the trap pumped full. This bottleneck trap contains 1,750 tcf of gas in place. Commercial gas accumulations are present in the Deep basin where coarser-grained marine shoreline sands occur. These are most numerous in the Elmworth area but are also present in five specific trends to the south. The gigantic oil and gas accumulations of the Lower Cretaceous make the Western Canada sedimentary basin the richest hydrocarbon province in the world.

Development Planning and Management of Petroleum Reservoirs Using Tank Models and Nonlinear Programming

Abstract: This paper demonstrates the feasibility of applying generalized reduced gradient nonlinear programming methods to solve optimal control models for petroleum reservoir development planning and management. The objective of the models is to maximize present value of profits, and their decision variables are how many wells to drill in each time period, the production rates, abandonment time, and platform size. The analysis uses tank-type reservoir models to describe the reservoir dynamics, and models both a gas reservoir with water drive, and a three phase oil reservoir. Results of several case studies on each model are presented. Extensions that consider spatial variation in the reservoir and use grid reservoir models are being investigated.

Clyde Field Growth Fault Secondary Detachment Above Basement Faults in North Sea

Abstract: The Clyde oil field in the southern North Sea comprises a Jurassic (Fulmar Sand) reservoir developed on a fault-bounded terrace on the margin of the Central graben. Palinspastic sections were constructed to honor seismic and well data, and were repeatedly tested using new techniques for balancing structural sections in extensional regimes. Cross-sectional area and bed-length balance clearly demonstrate the presence of both shallow and deep fault detachments. Seismic remapping has substantiated this model and demonstrates the decoupling of the basement and shallow listric fault sets. The new model has significance in terms of variations in reservoir quality and possible reservoir discontinuities resulting from fault seals. Of regional interest is the possibility of additio al growth-fault plays of this type within the North Sea basin.

Relationships of Source Rock, Thermal Maturity, and Overpressuring to Gas Generation and Occurrence in Low-Permeability Upper Cretaceous and Lower Tertiary Rocks, Greater Green River Basin, Wyoming, Colorado, and Utah: ABSTRACT

Abstract: Most hydrocarbon production from low-permeability Upper Cretaceous and lower Tertiary reservoirs in the Greater Green River basin of Wyoming, Colorado, and Utah is gas. The most likely sources of the gas are the interbedded coal beds and other carbonaceous lithologies. A source-rock evaluation of these rocks indicates predominantly humic, type III organic matter capable of generating mainly gas. The relatively closed nature of these low-permeability rocks facilitates examination of the geologic processes involved in gas generation and occurrence. All gas accumulations are associated with overpressuring. Thermal generation of gas is the main cause of overpressuring and is directly related to organic richness, level of organic maturation, and temperature. Distances of gas migration, in most areas, do not exceed a few hundred feet. Consequently, the temporal relationships of gas generation and migration with respect to the development of structural and stratigraphic traps are not as important as in more conventional reservoirs. On the basis of the premise of minimal gas migration, the initiation, or threshold of significantly large volumes of thermogenic gas occurs at a temperat re of about 190°-200°F (88°-93°C) and a vitrinite reflectance of about 0.80 Ro. End_of_Article - Last_Page 940------------

An experimental study of water imbibition in chalk from the Ekofisk Field

Abstract: The Ekofisk Field in the North Sea produces from two lithologically similar, low permeability fractured chalk formations. The Ekofisk Formation of Danian age is separated from the lower Tor Formation of Maastrichtian age by a tight zone of about 15 m thickness. With a projected primary recovery factor of only 18%, the secondary recovery target is substantial. A pilot waterflood has been conducted in the Tor Formation and expansion of waterflooding to a large area of the Tor is planned. For waterflooding to recover substantial oil in a highly fractured rock large saturation changes in the matrix rock must be achieved through water imbibition.

Lithology-Dependent Diagenetic Control of Reservoir Properties of Conglomerates, Falher Member, Elmworth Field, Alberta

Abstract: Conglomerates in the Falher Member of the Lower Cretaceous Spirit River Formation of Alberta are the reservoir rocks for the giant (2-3 Tcf or 5-8 × 1010 m3) Elmworth gas field. Three types of conglomerates are present: (a) unimodal--granules or pebbles lacking any matrix, (b) bimodal grain supported--a framework of pebbles with fine to medium sand in the interstices, and (c) bimodal sand supported--pebbles floating in fine to medium sandstone. The distribution of these three types is controlled by the original depositional environment. The granules and pebbles are composed of chert and silicified sedimentary and volcanic rock fragments. The sand grains are dominantly quartz. During diagenesis, very small (.01-0.1 mm) drusy quartz crystals form on the cherts and rock fragments, whereas quartz grains undergo heavy quartz overgrowth formation because of differences in nucleation and growth of quartz crystals. As a consequence, most unimodal conglomerates (low in quartz) have not experienced major reduction of porosity and permeability. Bimodal conglomerates, both sand and pebble supported, have lost significant amounts because of cementation of the quartz-rich matrix. Streaks and patches of kaolinite and calcite cements have also reduced porosity and permeability locally. Gas production from Falher wells, therefore, de ends not only on the amount of conglomerate, but also on the proportion of unimodal and bimodal types.

Controls on Hydrocarbon Accumulation in Glauconitic Sandstone, Suffield Heavy Oil Sands, Southern Alberta

Abstract: Hydrocarbon distribution in the Lower Cretaceous Glauconitic sandstone in the Suffield area of southeastern Alberta is controlled by three factors: sedimentology, structure, and mineralogy. The Glauconitic sandstone consists of six lithological facies interpreted to represent the lower-middle shoreface, middle shoreface, upper shoreface-foreshore, backshore, marsh, and lagoonal zones of a progradational, barrier-island system. Sediment deposited in the foreshore zone (laminated sandstone facies) has the best reservoir qualities: good porosity, low clay content, and good lateral continuity. The bioturbated, argillaceous sandstone, deposited in the backshore zone, has poor reservoir qualities: low porosity and high clay content with only isolated porous zones. Tidal inlet a d/or later stage fluvial channel deposits cutting through the sandstone trend form discontinuities in the reservoir. The hydrocarbon trapping mechanism is stratigraphic but with some structural influence. Deep faults, active during the deposition of upper Mannville sediments, caused differential subsidence and local thickening of sediment. This activity resulted in the apparent lateral juxtaposition of different facies. Parts of the Glauconitic sandstone form an exceptionally thick beach-shoreface sequence (up to 45 m or 148 ft thick). Faulting of sub-Cretaceous units may have controlled the rate of subsidence and the amount of sediment accumulation during deposition of the Glauconitic sandstone. The abundance of clay, mostly kaolinite, largely controls reservoir quality. Argillaceous backshore sandstones, which contain abundant detrital kaolinite, are poor reservoirs; clean foreshore deposits are good reservoirs. Porosity and permeability are only slightly reduced in the clean sandstone by formation of diagenetic phases such as kaolinite and quartz. During the wet forward-combustion recovery process, migration of kaolinite and dissolution-reprecipitation of silica could cause formation damage.

The Cretaceous Austin Chalk of South Texas--A Petroleum Source Rock

Abstract: Carbonate rocks commonly have been discounted as important source rocks because of their lower organic-carbon content and lower catalytic activity in comparison to shales. However, carbonate source rocks contain mostly sapropelic organic matter, which yields a higher percentage of oil earlier than the more humic organic matter of shales. Furthermore, carbonate source-reservoir sequences are at many places overlain by the perfect seal, evaporite, during the time of oil generation and accumulation. In contrast, many sandstone-shale sequences tend to leak petroleum during and after accumulation. The richest source rocks in the world are the argillaceous and siliceous carbonates in formations such as the Green River of Utah, the La Luna of Venezuela, and the Nordegg of the Western Canada basin. Carbonate rocks like the Cretaceous Austin Chalk of south Texas, which contains 60-90% CaCO3, act as both source and reservoir rock. Light-hydrocarbon analyses and pyrolysis data both support the concept that most of the oil in the Austin Chalk is autochthonous.

Maturation History and Thermal Evolution of Cretaceous Source Rocks of Bighorn Basin, Wyoming and Montana: ABSTRACT

Abstract: The Laramide basins of the Rocky Mountain region are deep asymmetric structural depressions containing thick sequences of Upper Cretaceous and Tertiary sandstone strata. The combined effects of tectonics and sedimentation have contributed to the thermal evolution of the basins and to the maturation history of the source rocks. In the Bighorn basin of Wyoming and Montana, total organic carbon (TOC) values for samples from a 2,000-ft (610-m) thick interval, including the Thermopolis, Mowry, Frontier, and Cody Formations, average 1 wt. %. The hydrogen indices and elemental analyses suggest that most of the samples presently contain kerogen between types II and III. The genetic potential of these samples suggests that they are moderately good source rocks. Vitrinite reflectan e values, production indices, elemental analyses, and the distribution of extractable hydrocarbons suggest that these Cretaceous source rocks can be within the liquid hydrocarbon window from a present day depth of 2,000-3,000 ft (610-914 m) down to 11,000-12,000 ft (3,353-3,658 m). On the basis of these observations, plus graphical and numerical thermal models for the Bighorn basin, it is suggested that (1) the Cretaceous section has generated hydrocarbons and could have produced the hydrocarbon production in the Bighorn basin, particularly from Cretaceous reservoirs, (2) migration distances for hydrocarbons into Cretaceous reservoirs could be short, (3) the stratigraphic and lateral distribution of marine sandstones intercalated within the Cretaceous source rocks provide ample opportunity for stratigraphic and/or diagenetic traps over a wide depth interval in this basin, and (4) owing to variations in thermal gradients within this basin, or similar Laramide-type basins, the hydrocarbon liquid window is expanded over a particular stratigraphic interval with dept . End_of_Article - Last_Page 937------------

Significant Role of Structural Fractures in Renqiu Buried-Hill Oil Field in Eastern China

Abstract: Renqiu oil field is in a buried hill of Sinian (late Precambrian) rocks located in the Jizhong depression of the western Bohai Bay basin in eastern China. The main reservoir consists of Sinian dolomite. The buried hill is a fault block bounded on the west side by a large growth fault that trends north-northeast and has throws of up to 1 km (3,300 ft). The source rocks for the oil are Tertiary sediments that overlie the Sinian dolomite. Structural fractures are the main factor forming the reservoir of the buried-hill oil field. Three dominant structural trends--northeast, north-northeast, and northwest--form the regional fracture system. The fractures are best developed along the north-northeast fault zones and at the intersections of other structural trends. Because the regional stress field altered during the late Mesozoic, the mechanical properties of north-northeast fault zones were changed from compressional shear to extensional shear. Consequently, the enlargement of the structural fractures provided good channels for the circulation of meteoric water. The north-northeast growth fault controlled the structural development of the fault block. The block was raised and eroded before the Tertiary sediments were dep sited, so the Sinian dolomite was exposed and underwent a long period of weathering and leaching. During the Eocene, the Jizhong depression subsided, but deposition, faulting, and relative uplift of the block occurred simultaneously as the block was gradually submerged. At the same time, several horizontal and vertical karst zones were formed along the fracture system by the circulating water. The Eocene source rocks lapped onto the block; therefore, the buried hill, with many developed karst fractures, was surrounded by a great thickness of source rocks. As the growth fault developed, the height of the fault block increased from 400 m (1,300 ft) before the Oligocene to 1,300 m (4,300 ft) after. As petroleum was generated, it migrated immediately along the growth fault into the karst-fracture system of the buried hill. The karst-fracture block reservoir has 800 m (2,625 ft) of oil-bearing closure and has good interconnected porosity between the leached fracture zones. Renqiu buried-hill oil field offers a high yield.

Predicting pore pressure and porosity from VSP data

Abstract: Presently, VSP is being used to predict interval velocity and depth beneath the drill bit. The method is to exploit special properties of the VSP to produce a successful inversion to acoustic impedance. Depth and interval velocity are derived from the acoustic impedance prediction. This technique is often a valuable aid in making drilling decisions. Other rock properties may be computed from the same data. Pore pressure is one such rock parameter that can be computed from interval transit times and depth. The product of interval transit times, depth, normal compaction ratios, and an area constant is pore pressure. Pore pressure prediction is as reliable as the predicted velocities and depths. In reservoir evaluation, and sometimes in the well completion program, porosity is the important rock property. The interval transit times predicted beneath the bit can be used to compute porosity. Unlike pore pressure, porosity computations require knowledge or assumptions about the rock matrix and shale percentages. For certain conditions these values are known. Further penetration of a reef in search of deeper porous zones is an example of a viable condition for porosity prediction. For both these rock properties the same conventions employed by well log analysis in modifyingmore » and interpreting results are needed. Where the parameters assumed fit the actual conditions, the results should have merit. If not, further interpretation is required.« less

Paleotemperature Analysis by Authigenic Minerals and Its Application to Petroleum Exploration

Abstract: Paleotemperature analysis in sedimentary basins is very important to petroleum exploration because generation of petroleum from kerogen is controlled mainly by temperature. Vitrinite reflectance generally is used for this analysis. A new technique of paleotemperature analysis depends on the relationship between transformation temperatures of authigenic minerals in diagenetically altered argillaceous sediments and their depth of first appearance in any specific well. Study of both the paleogeothermal gradient and porosity-depth relationships in a basin make possible predictions of hydrocarbon pools in the exploration area. For example, primary migration of oil in Neogene rocks of the Niigata basin in central Honshu, Japan, has occurred at burial depths between 2,260 and 3, 50 m (7,410 and 12,960 ft). This corresponds to the analyzed paleogeothermal gradients of exploited oil and gas fields in the basin (3.0° to 4.0°C/100 m = 1.6° to 2.2°F/100 ft).

Reservoir Facies Architecture in a Micro-Tidal Barrier System, Frio Formation, Texas Gulf Coast: ABSTRACT

Abstract: Barrier-bar sand bodies are a complex mosaic of barrier-core, shoreface, inlet-fill, tidal-delta, and back-barrier facies In addition, sandbody stratigraphy and internal depositional architecture are determined by the progradational, aggradational, or transgressive origin of the barrier complex The Frio barrier/strandplain system of the middle Texas Gulf Coast has produced more than 3 billion bbl of oil Examination of the Greta, Glasscock, and 41-A sands in West Ranch field illustrates the variability of barrier reservoirs Each reservoir is a mosaic of variably interconnected compartments having sheet, tab, pod, or channel geometries Conventional facies analysis (isolith and log-pattern mapping and limited core examination) combined with semiquantitative delineation of hydrocarbon-saturation distribution using resistivity logs defined the facies components of each reservoir The 41-A sand consists of juxtaposed progradational barrier-core, inlet-fill, and flood tidal-delta units The Glasscock sand is largely a transgressive barrier-flat and washoverfan deposit The Greta sand is a complex of aggradational barrier-core and inlet-fill facies Productive attributes of each reservoir are influenced by its facies architecture and attendant relative permeabilities Natural water drive is ineffective in the volumetrically restricted transgressive Glasscock reservoir Permeability distribution in the 41-A reservoir is facies defined Erratic injection response, irregular oil-water contact advance, and variable water/oil ratios observed during the productive history of individual reservoirs document localized facies effects on fluid flow Spatial variation of the gas/oil ratio may also reflect facies distribution End_of_Article - Last_Page 478------------

Fractured Shale Gas Reservoir Performance Study-An Offset Well Interference Field Test

Abstract: Gas-production characteristics of naturally fractured Devonian shale have been quantified through a three-well interference field test by use of an established producing well and two offsets placed on the primary and secondary regional fracture trends relative to the producer. Three individual shale zones were evaluated simultaneously by buildup, drawdown, and pulse tests to investigate reservoir gas flow characteristics, natural fracture properties, and gas storage and release mechanisms. Test results show severe permeability anisotropy, indicating elliptical drainage pattern with an 8:1 axis ratio. Essentially all gas is stored in a sorbed state in the shale matrix and is transported toward the wells through the native fracture system.

Geological Modeling of a Heterogeneous Sandstone Reservoir: Lower Jurassic Statfjord Formation, Brent Field

Abstract: A geological/reservoir engineering modelling study of the Brent field's Statfjord Formation reservoir is outlined as follows: it describes the geological characteristics of the reservoir, it illustrates how these features were incorporated into a detailed (32 layer) computer simulation model, and it summarizes some of the main conclusions concerning the nature of fluid flow through this heterogeneous reservoir in relation to possible field development scenarios. The study demonstrates how complex, threedimensional reservoir heterogeneity can be modelled with the latest type of large-capacity computers, such as the CRAY. Since these models are geologically more realistic, they can provide a better illustration of reservoir behaviour, which will improve performance prediction.

The Askeladden gas find — Troms I

Abstract: The Askeladden gas field lies in the central part of block 7120/8 in the Troms I area, approximately 100 km off the north Norwegian coast. The gas field covers a large part of the block. So far two wells have been drilled in the licence, and different gas—water contacts (GWC) have been found in the two wells. Reservoir rocks in the Askeladden field are sandstone sequences of mid and early Jurassic age. The post-mid Jurassic sediments contain no reservoir rocks, and consist predominantly of claystones, occasionally with streaks of limestone, dolomite and sandstone. Based on sedimentary structures and textures in the cores, the Middle and Lower Jurassic strata in the two wells are interpreted as a generally transgressive marine clastic coastal and inner shelf sequence. Below the reservoir lies several hundred metres of sandstones interbedded with minor shale layers.

Environment of Deposition And Reservoir Properties of the Woodbine Sandstone at Kurten Field, Brazos Co., Texas

Abstract: A combination of stratigraphic and diagenetic events has trapped oil in thin-bedded, clayey sandstones of the Upper Cretaceous Woodbine-Eagleford Formations. Five sandstone units occur in Kurten field and are designated from top to bottom as "A" through "E". Foraminifera and nannofossils indicate these units to be late Turonian. The "C" and "D" units are elongate north to south, 4.5 miles wide, over 10 miles long, and 40 feet thick. The "B" and "E" units are thinner and trend northeast to southwest. Grain size coarsens upward in the "B", "C", and "D" units, averaging 0.14 mm and ranging from 0.09 mm to 0.18 mm. Grain size fines upward in the "E" unit. The sandstone's average composition is 66 percent quartz, 1 percent feldspar, 2 percent rock fragments, and 28 percent matrix. Sedimentary structures in the "B", "C", and "D" units grade upward from laminated and bioturbated siltstones to clean sandstones with flaser cross-beds. The "E" unit consists of repeated bedsets similar to "cde" turbidite divisions. Sedimentary structures and bioturbation indicate that the units are offshore bars which have been formed by a combination of river mouth by-passing, storm-surge turbidity flows, and longshore currents. The porosity is largely diagenetic and occurs in the clayey beds. It appears to have been formed by fresh-water leaching along an erosional unconformity overlain by the Austin Chalk. Permeability becomes progressively poorer away from the unconformity; and a permeability barrier ultimately forms a poorly defined updip limit for the field, making Kurten field a combination diagenetic and stratigraphic trap. Relatively widespread occurrences of offshore bars suggest that similar traps may be fairly common in ancient shelf sediments.

Reservoir Compaction and Surface Subsidence in the Central Luconia Gas Bearing Carbonates, Offshore Sarawak, East Malaysia

Abstract: In the Central Luconia area, offshore Sarawak, substantial gas reserves are present in Miocene carbonate buildups. The carbonates consist of limestones and dolomites with porosities ranging from 0 to 40 percent. From core analysis it became evident that there exists a potential problem with regard to the compaction of the carbonate reservoir matrix as a result of effective stress increase as the reservoirs are depleted. Triaxial compaction tests were carried out on core samples from several carbonate reservoirs. It was found that highly porous mouldic limestones show pore collapse at relatively low effective stresses. After pore collapse the uniaxial compressibility coefficient increases significantly. Reservoir compressibility parameters can be derived from core data, for collapsing as well as non-collapsing rocks. These can be used to calculate reservoir compaction from well logs for a particular pressure decline. An estimate of the expected surface subsidence can be made based on the theory of poro-elasticity and the nucleus of strain concept as described by Geertsma. Predicted subsidence figures have been taken into account in platform design. The gas reservoirs have large aquifers within the carbonate buildups. As these aquifers have not all been fully appraised, there exists some uncertainty concerning their actual compaction behaviour.

Integrated Rock-Log Calibration in the Elmworth Field - Alberta, Canada: Reservoir Rock Detection and Characterization: Part I

Abstract: Integrated geological-petrophysical-reservoir engineering studies conducted within the Alberta basin, Canada, by Canadian Hunter Exploration, Ltd., resulted in the discovery of a number of gas fields, including the giant Elmworth field (Masters, 1979; and Sneider et al, 1983). These studies utilized rock-fluid data from cuttings, cores, well logs, and drill-stem and production tests to determine reservoir-rock potential and hydrocarbon saturation of thick, multiple Cretaceous sandstone and conglomerate intervals. These rocks typically range in porosity from 3 to 15% and in permeability from a few microdarcys to several darcys. Key elements in the exploration search and field exploitation are the evaluation of reservoir-rock quality, determination of the depositional facie containing the best reservoir rocks, and integrated log evaluation that identifies and quantifies lithology, porosity, and fluid type and distribution. This paper focuses on the rock-log part of the integrated studies and discusses the methodology used to establish accurate evaluations of pore space and hydrocarbons of all drilled wells. The paper is presented in three parts. The first part covers the evaluation and characterization of reservoir-rock properties primarily from well cuttings. The second part addresses rock-log calibration methods and describes "quick-scan" and digital log analysis techniques for accurate porosity and hydrocarbon saturation determination. The third part presents some examples that illustrate the methodology and results of rock-log calibration.

The pore geometries of reservoir rocks

Abstract: A ternary pore geometry classification scheme for reservoir rocks places intergranular and intercrystalline porosity at a common pole. These porosity types tend to have well interconnected pores and usually are good reservoirs. Intragranular, moldic, and vuggy porosity are grouped at another pole of the classification triangle. Rocks with these porosity types usually have poorly interconnected pores and low permeability. Rocks with microporosity are grouped at the final pole of the triangle. These may be argillaceous sandstones, finely textured carbonates, diatomites,or tripolitic cherts. Water‐wet microporous rocks hold bound water. Rocks with significant amounts of microporosity and/or intragranular, moldic, and vuggy porosity need fractures, either natural or induced, to make an attractive reservoir. Fracture porosity may occur by itself or combined with any other porosity type. Reservoirs typically contain multiple pore types, although one type often predominates. Large scale cavernous features in carbonates occasionally contain oil.

Influence of Depositional Facies on Hydrocarbon Production in the Tensleep Sandstone, Big Horn Basin, Wyoming: A Working Hypothesis

Abstract: Patterns of reservoir rock porosity and permeability characteristics in the Pennsylvanian Tensleep Sandstone are primarily the effects of grain packing fabrics and early diagenetic cements that are controlled by the environments in which the formation was deposited. These environments represent a regressive sequence of shoreface to eolian interbedded sands and dolomites. The formation has laterally correlatable tabular layers with strongly directional permeability in the eolian section. Tensleep reservoir characteristics may be interpreted from resistivity, density and sonic log responses once calibrated to porosity, permeability, saturation, and grain density analyses from a local full-section core, because reservoir and non-reservoir rocks have widely differing log responses. Directional permeability may be interpreted from dip logs. Because the controls on deposition are systematic rather than random, primary reservoir characteristics are predictable. Various of these characteristics have been reported in other papers for individual fields around the Big Horn Basin, and may be summarized as follows: Lower Tensleep moderately permeable shoreface sands interbedded with non-reservoir, relatively brittle dolostones. Upper Tensleep significantly more permeable, cross-stratified eolian sands with approximately 10:1 ratio of along-bedding-plane vs. through-bedding-plane permeability, appearing cyclically in composite sets of strata, which have non-reservoir, horizontal to wavy-bedded dolomitic sands at their bases.