Актуализация перспектив нефтегазоносности пермских отложений зоны сочленения Вилюйской синеклизы и Алданской антеклизы

The main subject of this monograph is a reconstruction of the history of deposition and facial development of Upper Jurassic and Lower Cretaceous deposits in the basement of the Carpathian Foredeep, based on data available from boreholes and a 3D seismic survey. The research area is located in the central part of the Carpathian Foreland, between two cities: Dąbrowa Tarnowska in the north-west and Dębica in the south-east. The new 3D seismic survey made in 2015 and the O-1 deep borehole – drilled in the same year and portraying a full profile of the Mesozoic sediments – allowed for much better recognition and documentation of many details of the geological structure of this previously poorly mapped area. The sedimentation of the carbonate formations of the Carpathian Foreland during the Late Jurassic and the Early Cretaceous took place in the shelf zone of the northern, passive margin of the Tethys Ocean. A characteristic feature of the Upper Jurassic sediments is their high facies diversity, due mainly to the presence of biohermal complexes and sets of layered marly-limestone sediments. Chapter 2 presents the geological structure of all structural stages in the area under study, including the lithological development, the lithostratigraphic divisions applied, and the regional palaeogeographic frameworks. Chapter 3 discusses both the history of research and the current state of knowledge regarding the Upper Jurassic and Lower Cretaceous carbonate sediments of the Carpathian Foreland. Chapter 4 describes the lithological characteristics of the carbonate sediments, considering lithostratigraphic units. This characterisation is based on a macroscopic examination of the available core material and analysis of the well logs. The lithostratigraphic profiles of selected deeper boreholes from the research area and its close vicinity document the current state of knowledge on lithostratigraphy and the facies development of the Upper Jurassic and Lower Cretaceous deposits. Chapter 5 features the microfacies and micropalaeontological characteristics of the carbonate sediments under study. Based on the results of many years of research and literature data, the possibilities of determining the age of every lithostratigraphic unit are discussed. Chapter 6 presents the analysis of the seismic 3D image based on selected seismic attributes. As part of the work, the following attributes are discussed: RMS Amplitude, Envelope, Instantaneous phase, Dominant frequency, Instantaneous bandwidth, Apparent polarity, Relative acoustic impedance, First derivative, Iso-frequency component, Time gain, Chaos, Variance (Edge method), and Local flatness. The analysis revealed additional important information regarding both the lithological development and the spatial range of sediments of individual lithostratigraphic units, at the same time facilitating the detailed location of fault zones. Based on the interpretation of the seismic image within the studied rock complex, the occurrence of angular unconformity, disturbance, and deformation zones related to synsedimentary tectonic as well as probable gravity-flow deposits are also documented. Chapter 7 presents lithofacial cross-sections constructed along selected seismic sections reflecting the spatial distribution and relationships between the sediments of individual lithostratigraphic units. Chapter 8 analyses the distribution of Upper Jurassic biohermal complexes in relation to the morphology of the Jurassic base surface. An analysis of the distribution of organic buildups belonging to the Huge Sponge-Microbial Bioherms Series, interpreted indirectly from seismic image, indicates two main areas where they can be found. These are the north-west part of the study area – where a quite extensive biohermal complex occurs (‘Complex N’), the exact range of which is difficult to determine due to later regional dolomitisation processes – and the area located in the central part of the seismic survey, where a complex of several very tall buildups with steep edges was found (‘Complex S’). Chapter 9 is devoted to the issue of the depositional history of the Late Jurassic–Early Cretaceous sedimentary basin of the Carpathian Foreland and to a discussion of the role of the most important factors influencing facies distribution in the research area. It has been shown that a characteristic feature of a large part of the Jurassic sediments is the strongly diachronic nature of the distribution of facies controlled by the varying bottom relief of the sedimentation basin and by some local factors related to synsedimentary tectonic episodes. The Sponge-Globuligerinid Series, beginning the profile of the Upper Jurassic sediments and representing the deepest sedimentation stage in the open shelf conditions, is characterised by a relatively high homogeneity of lithology in the whole Carpathian Foreland area. The ‘S’ biohermal complex developed over the elevated zone composed of several smaller tectonic elements, whilst the ‘N’ biohermal complex developed on a large, elevated part of the horst zone. The intensively developing ‘N’ and ‘S’ biohermal complexes affected successive deposition of the Late Jurassic sedimentary basin in the study area more and more. Those biohermal complexes were the source of the material redeposited into deeper parts of the sedimentary basin. On seismic profiles in the south-east neighbourhood of the ‘S’ biohermal complex, there is a characteristic high-amplitude record including the entire reflection set of variable dip angles. The frequent polarity changes which are visible within this zone in the Apparent polarity attribute, as well as the extremely variable range of values the Relative acoustic impedance attribute, prove the strong lithological differentiation of this rock complex. During the Tithonian time (sedimentation of the Coral-Oncolite Series), there was clear unification of the sedimentation conditions in the entire Carpathian Foreland area, mainly due to disappearance of the bottom relief diversity. At the same time another stage of dislocation reactivation occurred, as evidenced by the angular unconformity and the erosion traces of older sediments associated with this unconformity. The deposits of the Lower Shellbed-Oolite Series scattered throughout the research area represent various types of shallow-water sedimentation environments (including tidal, lagoon, and barrier zones) that developed in the Carpathian Foreland area on the borderline between the Late Jurassic and the Early Cretaceous. The sedimentation environment of the Marly-Shellbed Series dated to the Berriasian can be described as extremely shallow-water, with lagoon facies and under the influence of brackish environments. The sediments of the last two series of the Lower Cretaceous (i.e. the Mudstone-Limestone and Upper Shellbed-Oolite Series) represent the shallow-marine facies associated with marine transgression that took place during the Valanginian. The processes that have had the greatest impact on the current character and preservation of the rock series under study can be pinpointed and a comprehensive characterisation of these formations can be undertaken thanks to the depositional history of the Late Jurassic – Early Cretaceous sedimentary basin of the Carpathian Foreland presented herein, the macroscopic examination of the available core material, the microfacial and micropalaeontological analysis of individual lithostratigraphic units, and the interpretation of the seismic image. Keywords: Jurassic, Cretaceous, lithofacies, lithostratigraphy, biostratigraphy, seismic interpretation, seismic attributes

The objective of this study is to evaluate the Bahariya sandstone reservoir in the Al-Fadl and Al-Qadr fields within the North East Abu Gharadig Basin, Western Desert, Egypt. This evaluation utilizes qualitative and quantitative well log data from four wells: Alfadl-1, Alfadl-2, Alqadr-1, and Alqadr-6. Initial identification of potential reservoir zones was based on visual inspection of well log curves. Zones with favorable log responses, such as low gamma ray readings, positive resistivity separation, and neutron-density separation indicative of sandstone, were selected for further analysis. Key petrophysical parameters including shale volume, total porosity, effective porosity, and water saturation were calculated using established equations. The results indicate that Alfadl-1 well contains four promising zones (A, B, C, and D) characterized by high effective porosity (20% in average) and low water saturation (<50%). However, Alfadl-2 well did not reveal any significant reservoirs due to high shale content. Alqadr-1 well identified two promising zones (A and B) with effective porosities ranging from 13-19% and moderate water saturation ranging from 40-75%. Similarly, Alqadr-6 well showed three zones (A, B, and C) with effective porosities ranging from 13-18% and average water saturation of 50%. Overall, the Bahariya Formation exhibits potential hydrocarbon-bearing zones with varying degrees of reservoir quality, influenced by shale content and porosity levels. This evaluation provides a basis for further exploration and development in the North East Abu Gharadig Basin.

Subpermafrost aquifers are distinguished by their low stratum temperatures and pressures that approximate conventional hydrostatic pressures, rendering them suitable geological formations for the organization of underground gas storage facilities in a hydrate state. The design of such facilities requires the execution of experimental studies focused on hydrate formation within porous media. This paper examines the subpermafrost aquifers located in the Vilyui syneclise, where the hydrate stability zone covers Cretaceous and Jurassic deposits, specifically terrigenous-clayey strata. The mineralogical and granulometric composition, density, porosity, and moisture content, along with the presence of clays in the porous medium, influence the conditions conducive to hydrate formation. Therefore, the investigation of hydrate formation in clayey soils is a critical component that will support the development of underground gas storage facilities. To analyze the thermobaric conditions associated with hydrate formation, the method of differential thermal analysis was employed. The samples of porous media comprised clayey soils with varying moisture content, ranging from 15% to 40%. The results indicate that in soils with a moisture content of 20% or greater, a mechanical mixture of hydrates consisting of nearly pure methane and gases with higher molecular weights is produced. Additionally, it was observed that an increase in the moisture content of clay soils correlates with a decrease in the kinetic characteristics of hydrate formation. Based on the conducted research, it can be concluded that porous media characterized by clay layers with minimal moisture content are optimal for the establishment of underground gas storage facilities in a hydrated state.

It is well established that the oil &amp; gas industry has long surpassed its plateau for large discoveries. Thus, many companies have shifted their focus to cost-constrained policies for hydrocarbon discovery, making it difficult to have a strong sub-surface definition. Add the structural uncertainties and complexities of new discoveries in this scenario, the optimized field development becomes a real challenge. This study presents the development strategy established for a reservoir, with low seismic resolution, using the integrated dynamic data to define the reservoir structure and optimize its recovery.This paper focuses on a relatively new discovered formation in one of the oldest gas giants in Pakistan. The productive sandstone units are in beds with thicknesses ranging from 10-50m, separated by mudstone intervals. The low seismic resolution has posed a major challenge in finding the sweet spots for hydrocarbons above Gas-Water-Contact (GWC)-resulting in 60% well failures. Therefore, a workflow was developed to analyze various dynamic datasets in conjunction with the re-interpretation of seismic to delineate the reservoir structure. This included re-interpretation of MDT data and formation gradients, core re-evaluation, critical analysis of reservoir pressure variation, well failure analysis, thickness maps and PVT properties.The first four wells drilled in this reservoir had two successes, both in the Western compartment. However, sudden water production loaded up these wells only after 123 BCF production, which was a lower recovery as compared to GIIP estimates. After further geological evaluation and 3D seismic re-acquisition, more wells were drilled – revealing another deposition with a different GWC, but only 1 well was successfully completed as a producer, adding around 38% more reserve, while the others were again unsuccessful due to high structural uncertainty. This led to the development of a detailed algorithm for integrating dynamic data set with seismic re-interpretation and thickness mapping with the help of which two more wells were drilled and added around 22 % more reserves to the current mix. The dynamic data of these wells have now been further evaluated which revealed that the two compartments are in fact in communication with each other despite having a 60m difference in their GWCs. Finally, two more wells are now planned which will add around 10-20 % more recoverable volumes, giving an overall EUR of ~80% from these compartments.The main achievement of this workflow is a robust algorithm to integrate the dynamic data with geological interpretation to delineate a low-resolution reservoir since the seismic interpretation cannot be solely relied upon for developing such reservoirs. The paper also illustrates the robust engineering models and data analyses in a more systematic manner to ensure optimum locations for future wells to access, the otherwise, undrained locations.

Canada`s national centre for geoscience research and information is the Geological Survey of Canada (GSC). Two of its divisions, the Institute of Sedimentary and Petroleum Geology and the Atlantic Geoscience Centre work closely with the energy exploration and production industry and universities. One successful GSC innovation is the Industrial Farmers Program that promotes cost-shared projects on geoscience problems of mutual interest. An example is the Hydrocarbon Charge Modelling Project which has struck a series of mutually beneficial alliances among the GSC, oil and gas companies and universities. The GSC`s high quality skills in basin analysis, including sequence stratigraphy, biostratigraphy, structure and tectonics, petroleum geology, geophysics, geochemistry and environmental work are underpinned by vast data holdings on Canada`s mature Western Canada Sedimentary Basin and onshore/offshore frontier basins. Laboratory facilities include laser ablation ICP-mass spectrometry, gas chromatography-mass spectrometry, Rock-Eval/TOC, pyrolysis and thermal analysis, X-ray diffraction and fluorescence, scanning electron microscopy, organic and inorganic petrology and paleontology processing. Sophisticated computing facilities provide capabilities in basin and crustal modelling, 2- and 3-D seismic interpretation and seismic processing and computerised cartography. Solutions to the exploration, production and environmental problems faced by a cyclical business sector are mom efficiently sought through cooperative research by bringing togethermore » the diverse capabilities of industry, government and universities. Through such broad, collaborative partnerships society will ensure the economic and environmentally sustainable development of its future energy needs.« less

integration of gravity and magnetic data with seismic interpretations provides a definitive means of section validation. Traditionally this has been achieved as a two stage and separate process — seismic interpretation in the time domain and the potential fields model in the depth domain. Recent advances in software technology now enables interactive simultaneous real-time modelling of seismic gravity and magnetic data. In addition to conventional interpretations, modern uses of modelling now includes: quality control of seismic depth conversion, control of the potential field model using offset raytracing; derivation of a high quality depth model as a starting point for processes like pre-stack depth migration or turning wave analyses. Integration too can be used to differentiate between geometrically similar but lithologically different seismic structures. This paper describes the advantages of dynamically linking velocity, density and susceptibility in the modelling process illustrated by three different North Sea geological examples. (a) Depth-velocity modelling of salt structures in the Central Graben. (b) Structural interpretations of the Rattray volcanic rocks in the Outer Moray Firth. (c) Shallow sand channels and velocity models from high resolution aeromagnetic data.

Seismic azimuthal anisotropy (SAA) is observed in many areas of the Earth, and fast polarized directions (ϕ) have been mapped using earthquake surface waves and teleseismic S wave splitting over large regional and tectonic scales. Higher‐resolution petroleum exploration data, including 3‐D seismic surveys and dipole shear logs, often exhibit azimuthal anisotropy; however, we are unaware of any published studies mapping SAA from exploration‐scale data to study large‐scale regional and tectonic SAA trends. The physical mechanisms causing SAA in earthquake data are a subject of great interest; comparing regional ϕ trends to the higher‐resolution exploration trends may help understand these mechanisms. We present a SAA analysis using seismic exploration data across the North West Shelf (NWS) of Australia. We map the fast polarization directions ϕ from 34 dipole shear logs and two 3‐D seismic surveys and compare them to in situ maximum horizontal stress orientations (σH). Our results show that the ϕ and σH trends correlate across a geographical area spanning almost 2000 km and are similar to published results in the region from earthquake seismology. These results suggest that differential horizontal stress is the likely mechanism causing SAA at a wide range of spatial scales on the NWS of Australia. We also show that SAA is not observed at exploration scales in some areas of the NWS and propose a lithology‐dependent stress sensitivity model in which SAA is strongest in clean, unconsolidated quartz‐dominated sandstones and weaker or nonexistent in well‐consolidated cemented rocks and shale‐dominated sediments.

The Canning Basin is a largely unexposed and underexplored frontier basin, formed mostly in the Paleozoic. Geological knowledge of this basin is based predominantly on sparse regional “vintage” two-dimensional seismic and small three-dimensional (3-D) seismic surveys and less than 230 exploration wells. Following seismic interpretation, an integrated interpretation was completed on airborne gravity gradiometer (AGG), magnetic, seismic, well, and complementary data along the southwestern margin of the Fitzroy trough and Gregory subbasin. Seismic data were reinterpreted using AGG data to produce a better constrained geological model. A basement structure map, two intrasedimentary structure maps, and a formation distribution map were produced. The interpretation of seismic profiles, validated through 2.5-dimensional gravity gradiometer modeling, is essential to this workflow. Repeatedly reactivated west–northwest and northwest structural trends, inherited from Proterozoic orogenies, respectively delineate the Fitzroy trough and the Gregory subbasin with its northwestern structural extension into the Fitzroy trough, the Gregory subbasin trend. Subsidence occurred during two periods of extension. An asymmetric extensional system of the Fitzroy trough controlled Ordovician–Silurian deposition of the Carribuddy Group. Devonian–Carboniferous subsidence defines the Gregory subbasin trend. This Pillara extension reactivated structures in the east of the Fitzroy trough. Simultaneous activity of both extensional fault systems and growth faulting controlled the facies and thickness distribution of carbonates and clastics of the early Carboniferous Fairfield Group. The Meda and Fitzroy transpressional phases inverted faults of the Gregory subbasin trend and Fitzroy trough, producing prospects by structural interference. The improved understanding of tectono-stratigraphic relationships, including the 3-D distribution of carbonate reservoirs, benefited the planning of seismic surveys, prospect evaluation, drilling, and acreage relinquishment.

Oil and gas companies in order to maintain their efficiency in the conditions of: liberalization of markets, globalization, increased competition, reduction of consumer loyalty, constant variation in oil and gas prices, further development of Industry 4.0 and the Big Data factor, growing costs for drilling and completion – must have a flexible environment of information technologies that enables seamless and efficient sharing of knowledge throughout the company and along the entire value chain. One of the elements of this task is the effective use of hybrid knowledge-oriented decision support systems (DSS). This, in particular, determines the future stage of complex author's research – the development of a complex perforating knowledge management policy of an oil and gas company, the key tool for the implementation of which will be the hybrid, knowledge-oriented DSS considered in this publication.The form of knowledge representation has a significant impact on the characteristics and properties of a knowledge-oriented system. Therefore, based on the specifics of the exploration and development of oil and gas fields and the main advantages of the rule-oriented model of the DSS knowledge base, it is possible to conclude that it is necessary to use the KB rule-oriented basis for the DSS of an oil and gas production company. The rule-oriented subsystem is the main one in the knowledge-oriented DSS of an oil and gas production company, in fact, other subsystems provide it with analyses, assessments, and knowledge. Namely, the final product of the system: recommendations for making management decisions is carried out by a rule-oriented subsystem. In general, scientifically based conclusions were obtained regarding the knowledge-oriented architecture of the intellectual DSS of an oil and gas company, the basic model of knowledge presentation (production), the features of the mechanism of logical conclusion (direct logical conclusion), the conflict resolution procedure (a method of ordering products), etc. In the oil and gas industry, DSS built according to a hybrid approach have the greatest application potential – which are a powerful tool for solving complex specific problems of an oil and gas company. Therefore, in this work, the principles of hybrid application of intelligent technologies and the knowledge-oriented basis of DSS of an oil and gas company were further developed.

Refined sedimentologic concepts and favorable economics accord further exploration for subtle hydrocarbon traps in mature areas such as Kansas. Upper Pennsylvanian sediments of the Lansing and Kansas City Groups in central and western Kansas represent a succession of cyclic reservoir carbonates and sealing shales deposited on a shallow cratonic shelf. A subsurface study conducted by the senior author demonstrates using cores that subaerial exposure occurred in many cycles during late regression across much of the shelf. This resulted in the flushing of the regressive carbonates by fresh or undersaturated water and the formation or redistribution of porosity in these rocks. Primary and diagenetic porosity that are observed in cores and keyed to well logs commonly are associated with paleohighs or breaks in slope across the shelf. Selected maps of structure, thickness, and porosity from logs integrated with diagenetic and depositional facies from cores together provide necessary criteria to define subtle reservoir trends with the regressive carbonate. A study of a shallow gas reservoir in the Nolans Limestone in central Kansas found that porosity is best developed in a transgressive dolomitic mudstone to moldic bivalve packstone. During later regressive sedimentation of the Nolans cycle hypersaline waters apparently percolated through the sediment and precipitated anhydrite and dolomitized the carbonate mud particularly in the upper Nolans. The gas reservoir is structurally high with flanking water production and exhibits improved porosity development over the structural crest. Gamma ray--neutron crossplots and facies-ratio mapping aid in recognition of this subtle carbonate facies of the lower Nolans. Characterizing carbonate facies and early diagenesis of these reservoirs in the framework of cyclic sedimentation is critical to minimizing risks in locating drill sites. Similar concepts as described here can be applied to other Middle and Upper Pennsylvanian and Lower Permian cyclic sequences in Kansas. End_of_Article - Last_Page 1501------------

This work is conducted to study the geological and petrophysical features of the Trenton- Black River limestone formation. Log curves, crossplots and mineral identification methods using well-log data are used to determine the components and analyze changes in lithology. Thirty-five wells from the Michigan Basin are used to define the mineralogy of Trenton-Black River limestone. Using the different responses of a few log curves, especially gamma-ray, resistivity and neutron porosity, the formation tops for the Utica shale, the Trenton limestone, the Black River limestone and the Prairie du Chien sandstone are identified to confirm earlier authors’ work and provide a basis for my further work. From these, an isopach map showing the thickness of Trenton-Black River formation is created, indicating that its maximum thickness lies in the eastern basin and decreases gradually to the west. In order to obtain more detailed lithological information about the limestone formations at the thirty-five wells, (a) neutron-density and neutron-sonic crossplots, (b) mineral identification methods, including the M-N plot, MID plot, ϱmaa vs. Umaa MID plot, and the PEF plot, and (c) a modified mineral identification technique are applied to these wells. From this, compositions of the Trenton-Black River formation can be divided into three different rock types: pure limestone, partially dolomitized limestone, and shaly limestone. Maps showing the fraction of dolomite and shale indicate their geographic distribution, with dolomite present more in the western and southwestern basin, and shale more common in the north-central basin. Mineral identification is an independent check on the distribution found from other authors, who found similar distributions based on core descriptions. The Thomas Stieber method of analysis is best suited to sand-shale sequences, interpreting hree different distributions of shale within sand, including dispersed, laminated and structural. Since this method is commonly applied in clastic rocks, my work using the Thomas Stieber method is new, as an attempt to apply this technique, developed for clastics, to carbonate rocks. Based on the original assumption and equations with a corresponding change to the Trenton-Black River formation, feasibility of using the Thomas Stieber method in carbonates is tested. A graphical display of gamma-ray versus density porosity, using the properties of clean carbonate and pure shale, suggests the presence of laminated shale in fourteen wells in this study. Combined with Wilson’s study (2001), it is safe to conclude that when shale occurs in the Trenton-Black River formation, it tends to be laminated shale.

Oil potential of the Lower Mesozoic deposits of the Khapchagai megaswell of the Vilyui syneclise

The Middle Caspian offshore is one of a few provinces of Russian shelf with not only explored and proved petroleum resources but also where active production is taking place. Main oil and gas bearing complexes are Jurassic terrigenous-carbonate and Cretaceous terrigenous. Jurassic deposits contain 88% of petroleum resources within the Sarmat-Kvalyn anticline zone which is a part of Prikum-Central-Caspian system of anticlines and troughs. Current level of exploration gives reasonable level of confidence to identify large and medium structures. New profitable prospects are believed to be found in structural-tectonic and nonanticline traps. Due to good seismic coverage, irregular distribution of drilled wells, long distances between some of zones and lateral changes of thickness and lithology of Jurassic deposits application of sequence-stratigraphy analysis is necessary. With application of this method Jurassic deposits were divided into sequences of 2nd and 3rd order and parasequences for the first time in area of Middle Caspian. Identification of system tracts allowed to describe character of sedimentation in Jurassic basin and to define reservoirs and potential seals and their distribution.

The Yurihara oil and gas field is located on the southern edge of Akita Prefecture, northeastern Japan. In this area, drilling, surface geological surveys and many seismic surveys have been used to investigate the geological structure. Wells drilled into the Nishikurosawa Basalt Group (NBG) of Miocene age found oil and gas reservoirs at depths of 1.5–2 km. Oil and gas are now being produced commercially and further exploration is required in the surrounding areas. However, since the neighbouring areas are covered with young volcanic products from the Chokai volcano, and have a rough topography, the subsurface distribution of the NBG must be investigated using other methods in addition to seismic reflection. According to the well data, the resistivity of the NBG is comparatively higher than that of the overlying sedimentary formations, and therefore the magnetotelluric (MT) method is expected to be useful for the estimation of the distribution of the NBG.An MT survey was conducted along three survey lines in this area. Each line trended east–west, perpendicular to the regional geological strike, and was composed of about 25 measurement sites. Induction vectors evaluated from the magnetic field show that this area has a two‐dimensional structure. The evaluated resistivity sections are in agreement with the log data. In conclusion, we were able to detect resistive layers (the NBG) below conductive layers. The results indicate that the NBG becomes gradually less resistive from north to south. In the centre of the northern line, an uplifted resistive area is interpreted as corresponding to the reservoir. By comparison with a seismic section, we prove the effectiveness of the integration of seismic and MT surveys for the investigation of the morphology and internal structure of the NBG. On other survey lines, the resistive uplifted zones are interpreted as possible prospective areas.

Australia's first offshore production, in the Gippsland basin of southeastern Australia, was discovered in 1965. Further exploratory drilling in the area has led to the discovery of additional oil and gas fields. The Halibut oil field, currently being developed, is considered as a field case history of this Australian offshore operation. The field was discovered, by drilling only 1 exploratory well, in August 1967. It is 40 mi offshore in 238 ft of water and encompasses an area of 11 sq mi. At this early stage, the confidence factor on the seismic interpretation was sufficient to construct a 24-conductor drilling platform. Oil, associated with a common oil-water contact, is found at the top of the Latrobe complex of Paleocene rocks between depths of 7,400 and 7,856 ft subsea. Stratigraphically the reservoir is composed of braided stream sandstones with some point bar and stream mouth bar sandstones that have been subdivided and mapped as 8 units separated by impermeable breaks. These strata, dipping monoclinally westward, are truncated by a post-Eocene angular unconformity. Closure in excess of 500 ft is provided at the unconformable surface by the combination of erosion and post-Oligocene tilting. The field is being developed by drilling deviated wells, some in excess of 45° and 6,000 ft from the centrally located platform. With an available maximum of only 24 conductors, optimum drainage points must be selected with care. The number of wells to be drilled to any specific sandstone unit is based on its respective percentage of total reserves. The optimum drainage position is then determined from structure and isopach maps where individual sandstone units are in their highest nontruncated structural position. End_of_Article - Last_Page 333------------