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1
Kakarash, Tariq, and Qays M. Sadeq. "Development Permeability prediction for Bai Hassan Cretaceous Carbonate Reservoir." UHD Journal of Science and Technology 2, no. 1 (May 25, 2018): 8. http://dx.doi.org/10.21928/uhdjst.v2n1y2018.pp8-18.
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Permeability and porosity are the most difficult parameters to estimate in the oil reservoir because they are varying significantly over the reservoir, especially in the carbonate formation. Porosity and permeability can only be sampled at the well location. However, porosity is easy to estimate directly from well log data, permeability is not. In addition, permeability measurements from core samples are very expensive. Carbonate reservoirs are very difficult to characterize because of their tendency to be tight and heterogeneous due to deposition and diagenetic processes. Therefore, many engineers and geologists try to establish methods to get the best characterization for the carbonate reservoir. In this study, available routine core data from three wells are used to develop permeability model based on hydraulic flow unit method (HFUM) (RQI/FZI) for cretaceous carbonate middle reservoirs of Bai Hassan oil field. The results show that the HFUM is work perfectly to characterize and predict permeability for uncored wells because R2 ≥ 0.9. It is indicating that permeability can be accurately predicted from porosity if rock type is known.
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Xi, Kelai, Yingchang Cao, Keyu Liu, and Rukai Zhu. "Factors influencing oil saturation and exploration fairways in the lower cretaceous Quantou Formation tight sandstones, Southern Songliao Basin, China." Energy Exploration & Exploitation 36, no. 5 (January 2, 2018): 1061–85. http://dx.doi.org/10.1177/0144598717751181.
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Favorable exploration fairway prediction becomes crucial for efficient exploration and development of tight sandstone oil plays due to their relatively poor reservoir quality and strong heterogeneous oil saturation. In order to better understand the factors influencing oil saturation and favorable exploration fairway distribution, petrographic investigation, reservoir properties testing, X-ray diffraction analysis, oil saturation measurement, pressure-controlled mercury injection, and rate-controlled mercury injection were performed on a suite of tight reservoir from the fourth member of the Lower Cretaceous Quantou Formation (K1q4) in the southern Songliao Basin, China. The sandstone reservoirs are characterized by poor reservoir properties and low oil saturations. Reservoir properties between laboratory pressure conditions and in situ conditions are approximately the same, and oil saturations are not controlled by porosity and permeability obviously. Pores are mainly micro-scale, and throats are mainly nano-scale, forming micro- to nano-scale pore–throat system with effective connected pore–throat mainly less than 40%. Oil emplacement mainly occurs through the throats with average radius larger than 0.25 µm under original geological condition. Moreover, the samples with higher oil saturation show more scattered pore and throat distributions, but centered pore–throat radius ratio distribution. Pore–throat volume ratio about 2.3–3.0 is best for oil emplacement, forming high oil saturation. Quartz overgrowth, carbonate cements, and authigenic clays are the major diagenetic minerals. The reservoirs containing about 4–5% carbonate cements are most preferable for oil accumulation, and oil saturation increases with increasing of chlorite as well. The flow zone indicator is a reasonable parameter to predict favorable exploration targets in tight sandstone reservoirs. The reservoirs with flow zone indicator values larger than 0.05 can be regarded as favorable exploration targets in the K1q4 tight sandstones. According to the planar isoline of average flow zone indicator value, the favorable exploration targets mainly distribute in the delta plain distributary channel and deltaic front subaqueous distributary channel.
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Ahmed, Rayan. "Geological Model for Mauddud Reservoir Khabaz Oil Field." Iraqi Geological Journal 54, no. 1D (April 30, 2021): 29–42. http://dx.doi.org/10.46717/igj.54.1d.3ms-2021-04-23.
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The Mauddud reservoir, Khabaz oil field which is considered one of the main carbonate reservoirs in the north of Iraq. Recognizing carbonate reservoirs represents challenges to engineers because reservoirs almost tend to be tight and overall heterogeneous. The current study concerns with geological modeling of the reservoir is an oil-bearing with the original gas cap. The geological model is establishing for the reservoir by identifying the facies and evaluating the petrophysical properties of this complex reservoir, and calculate the amount of hydrocarbon. When completed the processing of data by IP interactive petrophysics software, and the permeability of a reservoir was calculated using the concept of hydraulic units then, there are three basic steps to construct the geological model, starts with creating a structural, facies and property models. The reservoirs were divided into four zones depending on the variation of petrophysical properties (porosity and permeability). Nine wells that penetrate the Cretaceous Formation (Mauddud reservoir) are included to construct the geological model. Zone number three characterized as the most important due to it Is large thickness which is about 108 m and good petrophysical properties are about 13%, 55 md, 41% and 38% for porosity, permeability, water saturation and net to gross respectively. The initial oil and gas in place are evaluated to be about 981×106 STB and 400×109 SCF.
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Fu, Siyi, Zhiwei Liao, Anqing Chen, and Hongde Chen. "Reservoir characteristics and multi-stage hydrocarbon accumulation of the Upper Triassic Yanchang Formation in the southwestern Ordos Basin, NW China." Energy Exploration & Exploitation 38, no. 2 (August 19, 2019): 348–71. http://dx.doi.org/10.1177/0144598719870257.
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The Chang-8 and Chang-6 members of the Upper Triassic Yanchang Formation (lower part) are regarded as the main oil producing members of the Ordos Basin. Recently, new hydrocarbon discoveries have been made in the upper part of the Yanchang Formation (e.g., Chang-3) in the southwestern Ordos Basin, implying that this interval also has a good potential for hydrocarbon exploration. However, studies on the origin of the high-quality reservoir, hydrocarbon migration, and accumulation patterns remain insufficient. In this study, integrated petrological, mineralogical, and fluid inclusion tests are employed to evaluate reservoir characteristics, and reconstruct the history of hydrocarbon migration and accumulation during oil and gas reservoir formation. The results reveal that the Yanchang Formation is characterized by low porosity (8 − 14%), medium permeability (0.5 − 5 mD), and strong heterogeneity; the reservoir properties are controlled by secondary porosity. Two types of dissolution are recognized in the present study. Secondary pore formation in the lower part of the formation is related to organic acid activity, while dissolution in the upper part is mainly influenced by atmospheric fresh water associated with the unconformity surface. The Yanchang Formation underwent hydrocarbon charging in three phases: the early Early Cretaceous, late Early Cretaceous, and middle Late Cretaceous. A model for hydrocarbon migration and accumulation in the Yanchang reservoirs was established based on the basin evolution. We suggest that hydrocarbon accumulation occurred at the early stage, and that hydrocarbons migrated into the upper part of the Yanchang Formation by way of tectonic fractures and overpressure caused by continuous and episodic hydrocarbon expulsion during secondary migration, forming potential oil reservoirs during the later stage.
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Carpenter, Chris. "3D Geological Model Creates Potential for Increased Production in Libyan Field." Journal of Petroleum Technology 73, no. 08 (August 1, 2021): 44–45. http://dx.doi.org/10.2118/0821-0044-jpt.
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This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 201417, “Reservoir Characterization and Geostatistical Model of the Cretaceous and Cambrian-Ordovician Reservoir Intervals, Meghil Field, Sirte Basin, Libya,” by Mohamed Masoud, Sirte Oil Company; W. Scott Meddaugh, SPE, Midwestern State University; and Masud Eljaroshi Masud, Sirte Oil Company, prepared for the 2020 SPE Annual Technical Conference and Exhibition, originally scheduled to be held in Denver, Colorado, 5–7 October. The paper has not been peer reviewed. The study outlined in the complete paper focuses on developing models of the Upper Cretaceous Waha carbonate and Bahi sandstone reservoirs and the Cambrian-Ordovician Gargaf sandstone reservoir in the Meghil field, Sirte Basin, Libya. The objective of this study is to develop a representative geostatistically based 3D model that preserves geological elements and eliminates uncertainty of reservoir properties and volumetric estimates. This study demonstrates the potential for significant additional hydrocarbon production from the Meghil field and the effect of heterogeneity on well placement and spacing. Introduction The reservoir of interest consists of three stratigraphic layers of different ages: the Waha and Bahi Formations and the Gargaf Group intersecting the Meghil field. The Waha reservoir is a porous limestone that forms a single reservoir with underlying Upper Cretaceous Bahi sandstone and Cambro-Ordovician Gargaf Group quartzitic sandstone. The Waha provides excel-lent reservoir characteristics. The Bahi has fair to good reservoir characteristics, while the Gargaf Group has very poor reservoir quality. The Waha and Bahi contain significant amounts of hydrocarbons. The Bahi is composed of erratically distributed detritus from the eroded Gargaf Group. The characteristic of the Gargaf sediments is quartzitic sandstones indurate to a quartzite with low reservoir quality.
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Trewin, Nigel H., Steven G. Fryberger, and Helge Kreutz. "The Auk Field, Block 30/16, UK North Sea." Geological Society, London, Memoirs 20, no. 1 (2003): 483–96. http://dx.doi.org/10.1144/gsl.mem.2003.020.01.39.
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AbstractThe Auk Field is located in Block 30/16 at the western margin of the Central Graben. Block 30/16 was awarded in June 1970 to Shell/Esso, and the discovery well 30/16-1 spudded in September 1970. The well found oil in a complex horst block sealed by Upper Cretaceous chalk and Tertiary claystones. The field contained an original oil column of up to 400 ft within Rotliegend sandstones, Zechstein dolomites, Lower Cretaceous breccia and Upper Cretaceous chalk. Production by natural aquifer drive commenced from a steel platform in 1976, initially from the Zechstein carbonates and now predominantly from the Rotliegend sandstone. Artificial lift was installed in 1988 helping to maintain production at economic levels past the year 2000. A complex reservoir architecture with cross flow between the Rotliegend and Zechstein reservoirs, a strong aquifer causing early water breakthrough via faults, and a limited seismic definition led to significant production variations from the initial forecasts. Equally important for the field, horizontal well technology opened up additional reserves and accelerated production from the complex Rotliegend reservoir; the most recent volumetric estimate for the total field predicts an ultimate recovery of 151 MMBBL for the existing wells from a STOIIP of 795 MMBBL. Full field reservoir simulation and 3D seismic data acquisition took place since mid 1980s but only recently resulted in a satisfactory understanding of the reservoir behaviour.The field is situated about 270 km ESE from Aberdeen in 240-270 ft of water. It covers a tilted horst block with an area of 65 km2, located at the western margin of the Central Graben. The Auk horst is bounded on the west by a series of faults with throws of up to 1000 ft, the eastern boundary fault has a throw of 5000 ft in the north reducing in throw southwards. The best reservoir lithology in the Zechstein is a vuggy fractured dolomite, and in the Rotliegend dune slipface sandstones provide the majority of the production. Both reservoirs and the overlying Lower Cretaceous breccia shared a common FWL at 7750 ft TVDss. The 38° API oil with a GOR of 190 SCF/STB was sourced from organic-rich Kimmeridge Clay.
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YALIZ, A. "The Crawford Field, Block 9/28a, UK North Sea." Geological Society, London, Memoirs 14, no. 1 (1991): 287–94. http://dx.doi.org/10.1144/gsl.mem.1991.014.01.35.
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AbstractThe Crawford Field was discovered in 1975 in UK Block 9/28 and the first oil was produced in April 1989. The field has a complex structural history. The reservoir is located on a down-faulted, westward tilting faultblock along the western margin of the Viking Graben. The eastern margin of the faultblock is severely truncated at Base Cretaceous level. The main producing zones comprise Middle Jurassic (Brent Group equivalent) and Triassic (Skagerrak Formation) sandstones. The seal is formed by Cretaceous marls and limestones. Reservoir quality and thickness are extremely variable, and drainage areas are limited. The reservoir fluid is a medium gravity oil having a thin gas cap. Oil in-place is in the order of 130 MMBBL but recovery factors are expected to be low.
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Naji, Hassan S., and Mohammed Khalil Khalil. "3D geomodeling of the Lower Cretaceous oil reservoir, Masila oil field, Yemen." Arabian Journal of Geosciences 5, no. 4 (November 16, 2010): 723–46. http://dx.doi.org/10.1007/s12517-010-0226-y.
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Pinnock, S. J., A. R. J. Clitheroe, and P. T. S. Rose. "The Captain Field, Block 13/22a, UK North Sea." Geological Society, London, Memoirs 20, no. 1 (2003): 431–41. http://dx.doi.org/10.1144/gsl.mem.2003.020.01.35.
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AbstractThe Captain Field is located in Block 13/22a in the Western Moray Firth Basin of the UK North Sea, 80 miles NE of Aberdeen in a water depth of 340 ft. Hydrocarbons are trapped in two geographical regions, the Main and Eastern closures, both with a significant stratigraphic pinchout component. The principal reservoirs consist of turbidite sandstones of Lower Cretaceous age which have been informally subdivided into two stratigraphic units comprising the Upper and Lower Captain Sandstones. At the base of the preserved Jurassic section the Heather Sandstone, Oxfordian in age, provides a secondary reservoir. Reservoir quality is uniformly excellent in the Lower Cretaceous with in situ, Klinkenberg corrected permeability averaging 7 Darcies and porosity in the range 28-34%. The reservoir is generally poorly consolidated sandstone with the depth to the crest of the field at -2700 ft TVDss. The reservoirs contain a total oil-in-place of 1000 MMBO. The Upper Captain Sandstone has a small associated gas cap containing 16 BCF gas-in-place. The oil is heavy, by North Sea standards, with oil gravity ranging from 19° to 21° API and has high in situ viscosity, 150 to 47 cP, at the mean reservoir temperature of 87°F. The fluid properties and offshore location necessitate the employment of innovative horizontal drilling methods, completion design and artificial lift technology in order to achieve an economically viable field development. Extended reach horizontal wells, with reservoir completion lengths of up to 8000 ft, are drilled for all oil producers and water injectors. Development risks were significantly reduced following two appraisal drilling campaigns in 1990 and 1993 culminating with the successful drilling and extended testing of a prototype horizontal field development well (13/22a-10). The field is being developed in two phases, Area A and Area B. First oil production commenced from the Captain platform in March 1997 from Area A and the field now produces at between 50000 and 70000 BOPD. Area B development is now underway with first oil planned for December 2000. Completion of this phase of the development will increase the plateau production rate to 85000 BOPD.
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Hodgins, B., D. J. Moy, and P. A. Carnicero. "The Captain Field, Block 13/22a, UK North Sea." Geological Society, London, Memoirs 52, no. 1 (2020): 705–16. http://dx.doi.org/10.1144/m52-2018-92.
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AbstractThe Captain Field in Block 13/22a is in the Moray Firth region of the UK North Sea. The primary reservoirs are Lower Cretaceous turbidite sandstones of the Captain Sandstone Member. Upper Jurassic shallower-marine Heather Formation sandstones of Oxfordian age provide a secondary reservoir. Total oil in place exceeds 1 Bbbl; however, the oil is heavy and viscous, requiring the continuous application of innovative technologies to maximize economic recovery from the field. Captain has been producing since 1997, with reservoir waterflood planned from the outset. Captain has been developed using long horizontal producers to maximize reservoir contact. Water injectors provide pressure support, with the aim of full voidage replacement. The Captain development has been phased with facilities consisting of two bridge-linked platforms, a floating production, storage and offloading vessel, and two subsea manifolds. Peak oil rate (100 000 boepd) was achieved in 2002. Average production in 2019 was 28 000 boepd. Captain is executing a chemical enhanced oil recovery (EOR) project, a first for the UK North Sea. Conventional waterflood yields an estimated ultimate recovery of 30–40%. Chemical EOR is expected to improve this by 5–20% in areas of the reservoir under polymer flood.
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Hayward, R. D., C. A. L. Martin, D. Harrison, G. Van Dort, S. Guthrie, and N. Padget. "The Flora Field, Blocks 31/26a, 31/26c, UK North Sea." Geological Society, London, Memoirs 20, no. 1 (2003): 549–55. http://dx.doi.org/10.1144/gsl.mem.2003.021.01.44.
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AbstractThe Flora Field straddles Blocks 31/26a and 31/26c of the UK sector of the North Sea on the southern margin of the Central Graben. The field is located on the Grensen Nose, a long-lived structural high, and was discovered by the Amerada Hess operated well 31/26a-12 in mid-1997.The Flora Field accumulation is reservoired within the Flora Sandstone, an Upper Carboniferous fluvial deposit, and a thin Upper Jurassic veneer, trapped within a tilted fault block. Oil is sourced principally from the Kimmeridge Clay Formation of the Central Graben and is sealed by overlying Lower Cretaceous marls and Upper Cretaceous Chalk Group.Reservoir quality is generally good with average net/gross of 85% and porosity of 21%, although permeability (Kh) exhibits a great deal of heterogeneity with a range of 0.1 to <10000mD (average 300 mD). The reservoir suffers both sub-horizontal (floodplain shales) and vertical (faults) compartmentalization, as well as fracturing and a tar mat at the oil-water contact modifying flow and sweep of the reservoir. Expected recoverable reserves currently stand at 13 MMBBL
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He, Mingyu, Qingbin Xie, A. V. Lobusev, M. A. Lobusev, and Xinping Liang. "Overview of Lower Cretaceous Achimov Formation: Physical Properties and Their Distribution Pattern in West Siberian Basin, Russia." Geofluids 2021 (April 6, 2021): 1–9. http://dx.doi.org/10.1155/2021/5560117.
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The Achimov Formation is one of the most important oil- and gas-bearing strata in the West Siberian basin in Russia. The total estimated reserves of this stratum exceed one billion tons. The formation was first explored in 1981, but it remains largely underdeveloped due to its deep burial depth and poor physical properties. Therefore, further research on the genetic mechanisms and distribution characteristics of the reservoirs in the formation can contribute to its further exploitation. The Achimov Formation is dominated by of fine- to medium-grained sandstones interbedded with shale. Based on analysis of well logging data, hand specimens, and previous research, this study analyzed the properties of three members (Ach1, Ach2, and Ach3) of the Achimov Formation and summarized their distribution patterns. Research on reservoir rocks from different oil and gas fields reveals varying physical properties across the formation with permeability and porosity increasing from the northern to central areas and decreasing from the central to the southern areas. Burial depth is one of the major controlling factors for reservoir properties in the formation. Reservoirs in both the northern and southern parts of the formation are buried deeper than those in the central areas, resulting in a disparity in reservoir quality.
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Abdelnabi, Abdalla A., Yousf Abushalah, Kelly H. Liu, and Stephen S. Gao. "Integrated geologic, geophysical, and petrophysical data to construct full field geologic model of Cambrian-Ordovician and Upper Cretaceous reservoir formations, Central Western Sirte Basin, Libya." Interpretation 7, no. 1 (February 1, 2019): T21—T37. http://dx.doi.org/10.1190/int-2017-0236.1.
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The Cambrian-Ordovician and Upper Cretaceous formations, which are the main oil-producing formations in the central Sirte Basin, are structurally complex. The lateral and vertical heterogeneity of the reservoir formations is not well-understood, which negatively affects the performance of the reservoirs. We constructed efficient full-field static models that incorporate the lateral and vertical variation of those reservoir formations by integrating geologic and geophysical data. We determined lithology and reservoir properties by selecting appropriate petrophysical techniques that suit the available well data and overcome issues with unreliable well-log measurements. In the process of building structural models, defining and mapping the base of the Cambrian-Ordovician Gargaf Formation was very challenging because wells did not penetrate the basal formation, and the quality of the seismic data decreases with depth. Therefore, we applied techniques of adding isochore maps of the overlying Upper Cretaceous of the Bahi and Waha Formations to map basal contact and determine the thickness of the Gargaf Formation for the first time in the area. The constructed isochore maps showed the thickness variation and the distributions of the Bahi and Waha Formations and explained the influence of Gargaf paleotopography and faults on them. The fault models combined with facies and property models suggested an interconnection among the three main reservoirs. They also indicated that the quality of the Waha reservoir enhances as the lithology varies from limestones to calcareous sandstones, whereas the quality of the Gargaf reservoir was primarily controlled by fractures. The total estimate of the original oil in place with the largest contribution of hydrocarbon volume from the Waha Formation was [Formula: see text] stock tank barrel. The created model with a fine-scale geocellular covering an area of [Formula: see text] is unique to the study area and it can be updated and refined at any time with new data production and drilling activities.
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Holdsworth, R. E., R. Trice, K. Hardman, K. J. W. McCaffrey, A. Morton, D. Frei, E. Dempsey, A. Bird, and S. Rogers. "The nature and age of basement host rocks and fissure fills in the Lancaster field fractured reservoir, West of Shetland." Journal of the Geological Society 177, no. 5 (November 29, 2019): 1057–73. http://dx.doi.org/10.1144/jgs2019-142.
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Hosting up to 3.3 billion barrels of oil in place, the upfaulted Precambrian crystalline rocks of the Lancaster field, offshore west of Shetland, give key insights into how fractured hydrocarbon reservoirs can form in such old rocks. The Neoarchean (c. 2700–2740 Ma) charnockitic basement is cut by deeply penetrating oil-, mineral- and sediment-filled fissure systems seen in geophysical and production logs and thin sections of core. Mineral textures and fluid inclusion geothermometry suggest that a low-temperature (<200°C) near-surface hydrothermal system is associated with these fissures. The fills help to permanently prop open fissures in the basement, permitting the ingress of hydrocarbons into extensive well-connected oil-saturated fracture networks. U–Pb dating of calcite mineral fills constrains the onset of mineralization and contemporaneous oil charge to the mid-Cretaceous and later from Jurassic source rocks flanking the upfaulted ridge. Late Cretaceous subsidence and deposition of mudstones sealed the ridge, and was followed by buoyancy-driven migration of oil into the pre-existing propped fracture systems. These new observations provide an explanation for the preservation of intra-reservoir fractures (‘joints’) with effective apertures of 2 m or more, thereby highlighting a new mechanism for generating and preserving fracture permeability in sub-unconformity fractured basement reservoirs worldwide.Supplementary material: Analytical methods and isotopic compositions and ages are available at https://doi.org/10.6084/m9.figshare.c.4763237Thematic Collection: This article is part of the Geology of Fractured Reservoirs collection available at: https://www.lyellcollection.org/cc/the-geology-of-fractured-reservoirs
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Li, Yaohua, Yan Song, Zhenxue Jiang, Lishi Yin, Mo Chen, Pengyan Wang, Dan Liu, and Yunjin Ge. "The characteristics of tight oil sand reservoir-source assemblage in lacustrine basins: A case study of the Cretaceous Qingshankou Formation, Songliao Basin, northeast China." Interpretation 6, no. 2 (May 1, 2018): T299—T311. http://dx.doi.org/10.1190/int-2017-0060.1.
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The complicated source-reservoir-assemblage characteristics of lacustrine tight oil sand in China are the main controlling factors of tight reservoir oiliness (i.e., oil richness). Several studies have focused on qualitative description of source-reservoir-assemblage characteristics without quantitative assessment. In this study, reservoir-source-assemblage (RSA) has been evaluated quantitatively by fitting the RSA log in the evaluation of Qijia Depression in the Songliao Basin. Total organic carbon (TOC) and sand volume (Vs) logs are used to fit the RSA log in three steps: (1) TOC and Vs log fitting and normalization, (2) RSA log fitting, and (3) extraction of root-mean-square (rms) amplitude and frequency (Frq(0)) information from the RSA log. The rms represents the reservoir capability and hydrocarbon potential, and Frq(0) represents the interbedding frequency that changes with the lake level. Positive values (0–1] of the RSA log correspond to a high lake level, whereas negative values [[Formula: see text], 0) correspond to a low lake level. Based on RSA log values, we defined the parameter RSAsuf, a product of rms and Frq(0), to quantitatively evaluate the tight oil sweet spot. RSAsurf serves as tight oil sweet spot indicator and correlates positively to oil richness. As a result, four types of effective reservoirs (RI, RII, RIII, and RIV), two types of effective sources (SI and SII), and three types of RSAs (R-S-R, S-R-S, and S-S-R) are identified based on cores and RSA logs. High RSAsuf values on the isoline map indicate the sweet spot zones around the G933 and J392 well areas, which correlates very well with the oilfield test data. The approach is appropriate for lacustrine basins with complicated RSA, in which RSA logs serve as indicator for the sedimentary rhythm, reservoir capability, and hydrocarbon potential.
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Jha, M., T. Tran, and D. Hawkins. "GEOSTEERING OF TWO HORIZONTAL WELLS IN SOUTH UMM GUDAIR FIELD: A SUCCESSFUL CASE HISTORY." APPEA Journal 45, no. 1 (2005): 55. http://dx.doi.org/10.1071/aj04005.
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The South Umm Gudair (SUG) oil field located in the Neutral zone between Kuwait and Saudi Arabia has produced since 1968 from an active water drive carbonate reservoir of Lower Cretaceous age. The lower zones are homogenous intervals of higher permeability which appear to be sufficiently swept by natural water drive over a period of time. The upper zones of the reservoir have lower permeability, are relatively thin and are bound by tighter intervals that act as possible barriers to the natural water drive system.Geosteering techniques are now extensively used in oil and gas industry for horizontal wells to produce hydrocarbons from thin reservoirs to maximise recovery, and restricting water-coning problems. Recent advancements in well placement using Geosteering allow successful targetting of low permeability reservoir with great precision which results in exposing more drainage area in the target pay.The geosteering technique was considered for the first time in joint operation’s SUG field targetting two horizontal wells. Improved well productivity is achieved through optimised well placement. This success has led to a development plan and strategy of additional horizontal drilling locations to maximise recovery of un-swept oil from the low permeability reservoirs. This paper reviews the success of Geosteering in SUG’s two horizontal wells, completed in July 2004.
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Jin, KunQiang, and Yunfeng Zhang. "Formation Conditions and Exploration Directions of Large Cretaceous Sub-salt Oil and Gas Reservoirs in Santos Basin." E3S Web of Conferences 206 (2020): 01013. http://dx.doi.org/10.1051/e3sconf/202020601013.
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The rich oil and gas resources and good reservoir-forming conditions in the Santos Basin in Brazil make it a majorstrategic succession area for oil and gas exploration in the Santos Basin. The sub-salt bio-reservoir-cap configuration in the SantosBasin can be divided into two types: bio-reservoir-cap superposition and bio-reservoir superposition; the preservation conditions canbe divided into cap-slip-off extension deformation type, and the cap-layer is strongly extruded Deformation type, 3 types of capping stable extrusion deformation type; reservoir formation zone can be divided into 2 types: subsalt raw salt storage and subsalt raw salt storage. The high area outside the Santos Basin in the sub-salt source-salt storage zone is a favorable exploration direction for finding large oil and gas areas under the salt in the Santos Basin.
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Manceau, E., E. Delamaide, J. C. Sabathier, S. Jullian, F. Kalaydjian, J. E. Ladron De Guevara, J. L. Sanchez Bujanos, and F. D. Rodriguez. "Implementing Convection in a Reservoir Simulator: A Key Feature in Adequately Modeling the Exploitation of the Cantarell Complex." SPE Reservoir Evaluation & Engineering 4, no. 02 (April 1, 2001): 128–34. http://dx.doi.org/10.2118/71303-pa.
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Summary As with some thick and highly fractured Iranian fields, the Cantarell complex located offshore Mexico presents features [decreases in the production gas/oil ratio (GOR) and bubblepoint pressure with time] that reveal the effect of convection. This effect on the past homogenization of fluid properties is discussed and supported by a thorough characterization of the thermodynamic properties of actual reservoir fluids. To model convection, the reservoir simulator used for this study was purpose adapted. Sensitivity runs were performed to demonstrate the necessity of accounting for convection when matching the past history of the Akal field, which is part of the Cantarell complex. Introduction Presentation of the Cantarell Complex. The Cantarell complex is the most important oil field in Mexico, and the sixth-largest in the world. To economically optimize its value, it has been decided to initiate a major recovery process by injecting nitrogen for pressure-maintenance purposes. Cantarell field is a thick, highly fractured reservoir; therefore, it is the kind of reservoir where convection phenomena may occur. Convection is a complex process that is characterized by a vertical homogenization of fluid properties in the fractures. This may have an essential impact on production and injection profiles, in particular on the quantity of nitrogen in the effluents as well as nitrogen breakthrough times, and therefore on the overall nitrogen-injection efficiency. The Cantarell complex is located offshore approximately 85 km from Ciudad del Carmen. It includes four adjacent oil fields known as Akal, Chac, Kutz, and Nohoch. Akal is the largest oil accumulation, with more than 90% of the 35 billion barrels of oil in place. The reservoir is an anticline producing from the fractured carbonates of the Cretaceous and upper Jurassic formations, which also contain many vugs and caves. The Upper Cretaceous is the most fractured and brecciated. Fracturing decreases with depth in the Middle and Lower Cretaceous. The average thickness of the whole reservoir is about 775 m, and the depth of the top Cretaceous ranges between 1100 and 3600 m true vertical depth subsea (SS). Below the Cretaceous sequence, the Upper Jurassic (Oxfordian, Kimmeridjian, Tithonian) is a stratigraphic reservoir with poor reservoir characteristics. Field production started in June 1979, reaching a peak of 1.157 MMBOPD in April 1981, with 40 producing wells. A total of 184 wells were drilled in Cantarell, among them 173 wells in Akal alone. Cantarell crude is a 19 to 22°API Maya type, with an initial bubblepoint pressure close to 150 bar. Initially, the reservoir pressure was above the bubblepoint pressure and was equal to 266 bar at 2300 mSS; therefore, there was no initial gas cap. The reservoir pressure rapidly reached the bubblepoint pressure, and a secondary gas cap appeared in 1981. The gas/oil contact (GOC) was located at 1800 mSS in 1997. The corresponding cumulative oil production was around 5.5 billion STB. Accounting for Convection in Cantarell Complex. Cantarell field appears to have all the characteristics of a reservoir where convection may occur. As observed, for instance, in a major Iranian field,1 convection is a complex phenomenon that occurs in thick and highly fractured reservoirs. As explained in detail by Saidi,2 it results from a combination of thermal gradients, gas liberation at the GOC, and gravity segregation, and it is made possible by high vertical permeabilities. When the oil initially reaches the bubblepoint pressure, it liberates gas in solution, thus becoming heavier. Because of the high vertical permeability, this heavier oil can move downward while lighter oil heated from below expands and rises. A convection flux is then established, finally leading to a fast homogenization of the oil properties along the vertical depth. This leads to a reduction of the bubblepoint pressure in a vertical oil column. Indications that convection is taking place include more homogeneous oil properties and temperature on the vertical, change of the oil composition with time, and decline of bubblepoint pressure and production GOR with time. For Akal, producing GOR's were plotted vs. time for each well. The initial mean GOR value is approximately 90 vol/vol. The wells were organized into four classes: wells with decreasing then increasing GOR, wells with increasing GOR, wells with a constant GOR, and wells with a decreasing GOR. Fig. 1 shows a typical well with a decreasing behavior. Such a well generally begins producing with an initial GOR value of 90 vol/vol, then its GOR slowly decreases down to around 60 vol/vol. This means that the oil produced becomes heavier with time. Typically, this can be explained by convection. Fig. 2 shows the location of all the wells on the Cantarell field with their classification as of 1993. The corresponding GOC is also drawn. One can observe that the major part of the wells areally allocated close to the top of the structure, despite the vertical position of their completion, shows a GOR behavior other than constant as the reservoir pressure goes down, while the wells allocated through the flanks of the structure show a constant GOR behavior. This means that a complex phenomenon affecting the original fluid properties is taking place. Even though there is no evidence of convection, it is assumed that convection also takes place in the gas cap, leading to a faster homogenization in this area. However, this is not the main focus of this paper. To confirm this statement, three oil samples were taken in 1997 from three different zones of the reservoir: sample 1.07 was found close to the GOC, sample 1.11 was at an intermediate location, and sample 1.16 was in a deep zone, close to the water/oil contact (WOC). The bubblepoint pressures, as well as the flash GOR measured for each oil sample, are presented in Table 1. It can be observed that, for each crude sample, the oil is heavier than the initial oil in place and that the deeper the oil, the lighter it is.
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Pouderoux, Hugo F., Per K. Pedersen, and Adam B. Coderre. "Fluvial reservoirs stacked in thin deltaic successions of the Lower Cretaceous Grand Rapids Formation, east-central Alberta, Canada." Interpretation 3, no. 4 (November 1, 2015): T207—T232. http://dx.doi.org/10.1190/int-2014-0100.1.
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The Manatokan Field in east-central Alberta offers a unique opportunity to characterize paralic sandstone reservoirs in 3D using a dense network of well data (approximately [Formula: see text]). Within the [Formula: see text] study area, the 100-m thick Lower Cretaceous Grand Rapids Formation is dominantly composed of sediment deposited in two depositional environments: river-dominated deltas and marine-influenced fluvial rivers. Up to 33 individual fluvial bodies, occurring at five stratigraphic levels and eroding into deltaic parasequences, are identified in the oil-charged upper part of the formation. The width and thickness of fluvial bodies typically range from 50 to 9000 m and from 5 to 50 m, respectively. Examination of cores, wireline logs, and strategically located 3D seismic data indicates that fluvial bodies are dominantly filled by inclined heterolithic deposits emplaced as downflow translation point bars (PBs) separated by mud-filled abandoned channels. Although individual PBs are relatively small ([Formula: see text]), the dense subsurface data set provides the means to build facies maps that illustrate their internal architecture and the distribution of reservoir heterogeneities. Reservoir-quality sandstone occurs on the upstream portion of PBs and usually forms continuous beds along the base of fluvial bodies that extend underneath abandoned channel deposits. High reservoir connectivity along the base of these heterolithic fluvial bodies constitutes a major advantage for heavy oil reservoir production driven by gravity. Core evidences also indicate potential communication between fluvial bodies and surrounding deltaic sandstones or older underlying fluvial reservoirs, which may lead to unexpected results during field development. The Grand Rapids Formation provides a good subsurface analogue of complex marginal-marine clastic reservoirs, and its study may help to explain unanticipated production results in similar hydrocarbon areas.
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Carpenter, Chris. "Water-Shutoff Technique Extends Productive Life Cycle of Cretaceous Sandstone." Journal of Petroleum Technology 73, no. 04 (April 1, 2021): 51–52. http://dx.doi.org/10.2118/0421-0051-jpt.
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This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 199070, “Water-Shutoff Technique Extends the Productive Life Cycle of Cretaceous U Sandstone: The Iro Field Case in Ecuador,” by Luis Roberto Bailón, SPE, Ney Holger Orellana, SPE, and Santiago Villegas, Repsol, et al., prepared for the 2020 SPE Latin American and Caribbean Petroleum Engineering Conference, originally scheduled to be held in Bogota, Colombia, 17-19 March. The paper has not been peer reviewed. The water-shutoff technique is used in some wells of the U reservoir in the Iro field of the Oriente Basin in Ecuador as a remediation plan to restore production after an early water breakthrough. The production historical data, workovers, and sand-body correlation of wells are compared to understand reservoir behavior, shale-baffle-sealing continuity, the existence of different sand units, and the effect on production. Introduction The Iro field is in the south of Block 16. Production began in March of 1996. Iro is considered a mature field that produces heavy crude oil. The U sand-stone reservoir at Iro field is constituted by quartz grains subtransparent with fine grain sizes to medium, moderately classified, occasionally clay-like matrix. A thin limestone layer subdivides the U sandstone reservoir into two main stratigraphic units, Upper U and Lower U sandstone. Logging acquisition during the drilling campaign revealed heterogeneous sand-body deposition throughout the field. Depositional features of fluvial channels are developed from the base of the reservoirs, which are overlaid by sand bars. In addition, interbedded shale layers and baffles are present in the U reservoir, in some cases locally. However, the main shale layers are effective seals when they subdivide the Upper and Lower U sandstone units into two or more subunits. A good example is the shale layer that separates channels and bars in the Lower U sandstone unit. This identification was possible after the development of the well-drilling campaign, well correlation, and years of production behavior. Two subunits of the Lower U reservoir, Ui1 and Ui2, were classified as a result of the acquired data. Cased-Hole Logs (Pulsed Neutron) Given the maturity of the fields, during the last 2 years, a logging campaign of pulsed-neutron cased-hole logs has been performed. In the case of the Iro field, pulsed-neutron logs were run in six wells; three of these reached the Lower U reservoir. These three wells have a good correlation between the analog density and neutron curves of the cased-hole and the original openhole curves, providing certainty in the reading of the tool. The logging program obtained data of chemical-element spectra in capture and inelastic modes. This information was processed and analyzed to derive hydrocarbon saturation. In this way, by-passed oil can be identified as well as reservoir zones already drained by production of the same wells or by neigh-boring wells. Data in the Lower U reservoir show fluid movement.
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Carpenter, Chris. "Applications of Artificial Neural Networks for Seismic Facies Classification." Journal of Petroleum Technology 73, no. 02 (February 1, 2021): 68–69. http://dx.doi.org/10.2118/0221-0068-jpt.
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This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 200577, “Applications of Artificial Neural Networks for Seismic Facies Classification: A Case Study From the Mid-Cretaceous Reservoir in a Supergiant Oil Field,” by Ali Al-Ali, Karl Stephen, SPE, and Asghar Shams, Heriot-Watt University, prepared for the 2020 SPE Europec featured at the 82nd EAGE Conference and Exhibition, originally scheduled to be held in Amsterdam, 1-3 December. The paper has not been peer reviewed. Facies classification using data from sources such as wells and outcrops cannot capture all reservoir characterization in the interwell region. Therefore, as an alternative approach, seismic facies classification schemes are applied to reduce the uncertainties in the reservoir model. In this study, a machine-learning neural network was introduced to predict the lithology required for building a full-field Earth model for carbonate reservoirs in southern Iraq. The work and the methodology provide a significant improvement in facies classification and reveal the capability of a probabilistic neural network technique. Introduction The use of machine learning in seismic facies classification has increased gradually during the past decade in the interpretation of 3D and 4D seismic volumes and reservoir characterization work flows. The complete paper provides a literature review regarding this topic. Previously, seismic reservoir characterization has revealed the heterogeneity of the Mishrif reservoir and its distribution in terms of the pore system and the structural model. However, the main objective of this work is to classify and predict the heterogeneous facies of the carbonate Mishrif reservoir in a giant oil field using a multilayer feed-forward network (MLFN) and a probabilistic neural network (PNN) in nonlinear facies classification techniques. A related objective was to find any domain-specific causal relationships among input and output variables. These two methods have been applied to classify and predict the presence of different facies in Mishrif reservoir rock types. Case Study Reservoir and Data Set Description. The West Qurna field is a giant, multibillion-barrel oil field in the southern Mesopotamian Basin with multiple carbonate and clastic reservoirs. The overall structure of the field is a north/south trending anticline steep on the western flank and gentle on the eastern flank. Many producing reservoirs developed in this oil field; however, the Mid- Cretaceous Mishrif reservoir is the main producing reservoir. The reservoir consists of thick carbonate strata (roughly 250 m) deposited on a shallow water platform adjacent to more-distal, deeper-water nonreservoir carbonate facies developing into three stratigraphic sequence units in the second order. Mishrif facies are characterized by a porosity greater than 20% and large permeability contrast from grainstones to microporosity (10-1000 md). The first full-field 3D seismic data set was achieved over 500 km2 during 2012 and 2013 in order to plan the development of all field reservoirs. A de-tailed description of the reservoir has been determined from well logs and core and seismic data. This study is mainly based on facies log (22 wells) and high-resolution 3D seismic volume to generate seismic attributes as the input data for the training of the neural network model. The model is used to evaluate lithofacies in wells without core data but with appropriate facies logs. Also, testing was carried out in parallel with the core data to verify the results of facies classification.
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Beacher, G. J. "PRESSURE STUDY OF THE FLACOURT FORMATION AQUIFER IN THE THEVENARD ISLAND AREA OF THE BARROW SUB-BASIN." APPEA Journal 38, no. 1 (1998): 438. http://dx.doi.org/10.1071/aj97021.
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Thevenard Island area lies in the offshore Carnarvon Basin off the northwest coast of Western Australia. The Flacourt Formation of the Cretaceous Barrow Group sequence is the primary oil-producing reservoir. West Australian Petroleum Pty Limited (WAPET) as operator on behalf of its participants (Chevron, Texaco, Shell and Mobil) has been producing from this reservoir since 1989. It has widely been held that in this area the relatively thick, multi-darcy Barrow Group oil accumulations have had infinite aquifer pressure support with no regional draw-down effect.After the commencement of oil production from the Flacourt Formation, wireline pressure surveys in exploration and development wells have indicated anomalous pressure trends in the reservoir. Initially, the accuracy of pressure gauges and elevation measuring devices were questioned.Recent studies based on WAPET's production history in the region and re-analysis of wireline pressure data have shown that the Flacourt Formation does experience regional draw-down in aquifer pressure due to production. This paper demonstrates the existence of draw-down and how this information has aided in the evaluation of the Flacourt Formation and the overlying Mardie Greensand reservoirs.
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Hu, Hai Yan, Zhe Zhao, Song Lu, and Hang Zhou Xiao. "Regional Seal as Key Controlled Elements of Petroleum Accumulation in the Rift Basin." Advanced Materials Research 524-527 (May 2012): 190–93. http://dx.doi.org/10.4028/www.scientific.net/amr.524-527.190.
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Rift basin is an important petroleum basin type, in which about one third of oil and gas was discovered. To research on the main controlled elements of oil and gas accumulation, five typical rift basins in Europe are focused on the geological condition such as source rock, reservoir, seal, petroleum system, and accumulation with logging, hole, measured and analytical methods, and so on. The results showed the main regional seal controlled the petroleum distribution in the rift basin. Seals are defined by main regional seal, minor regional seas and local region according to thickness, distribution, lithostratigraphy. Viking Graben of North Sea has main regional seal about 3000m thick during late Jurassic and Cretaceous, about 81 percent of petroleum is in the Jurassic reservoir; Anglo-Dutch basin has main region thick seal during Triassic through Jurassic, and Permian reservoir accounted for 73 percent of basin reserves; Voring Basin has the main regional seal during Cretaceous through early Tertiary, the Jurassic reservoir has 85 percent of whole basin reserves; Northeast and Northwest Germany Basins have the evaporites as main regional seals during late Permian, and Permian reservoir accounted for more than 80 percent of basin reservoir, respectively. Rift Basin can develop reservoir like turbidite, source rock, seal in the basin dynamic opinion. Some main regional seals may develop overpressre because of quick subside and hydrocarbon generation at some conditions, it can strengthen seal capability. Oil and gas can migration to the main regional seal by normal faults caused by rifting, which can stop further migration so that they were accumulated under the main regional seal.
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Rzyczniak, Mirosław, Marek L. Solecki, Dagmara Zeljaś, and Stanisław J. Dubiel. "THE EFFECT OF PRESSURE DEPRESSION ON THE WATER INFLOW VOLUME TO WELLS WHICH COVER CARBONATE ROCKS IN THE CARPATHIAN FOREDEEP BASEMENT, SE POLAND." Rudarsko-geološko-naftni zbornik 36, no. 2 (2021): 33–42. http://dx.doi.org/10.17794/rgn.2021.2.4.
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This paper presents an analysis of well testing data, performed with a Drill stem test (DST). The carbonate levels of Mesozoic reservoir rocks were investigated in the research area of the Carpathian Foredeep. Based on the results of 17 two-cycle DST reservoir tests, the dependence of the volume of the reservoir water flow rate from the Mesozoic carbonate reservoirs (Upper Jurassic, Lower Cretaceous) to the wells as a function of the mean depression of bottom pressure was researched in the selected oil exploration area in the Carpathian Foredeep basement, SE Poland. Using methods of statistical analysis, a satisfactory correlation between variables for power and the exponential model was found, and a weak correlation for the linear model was found. A decrease in the value of the reservoir water flow rate along with an increase in pressure depression was found for the Mesozoic carbonate reservoirs, which may indicate the occurrence of fractures and micro-fractures shortening under extreme pressure depression and blockage phenomena of fractures and cavernous pores in the perimeter area by solid particles (cuttings, salt, polymers, etc.).
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Nishikiori, N., and Y. Hayashida. "Investigation of Fluid Conductive Faults and Modeling of Complex Water Influx in the Khafji Oil Field, Arabian Gulf." SPE Reservoir Evaluation & Engineering 3, no. 05 (October 1, 2000): 401–7. http://dx.doi.org/10.2118/66223-pa.
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Summary This paper describes the multidisciplinary approach taken to investigate and model complex water influx into a water-driven sandstone reservoir, taking into account vertical water flux from the lower sand as a suspected supplemental source. The Khafji oil field is located offshore in the Arabian Gulf. Two Middle Cretaceous sandstone reservoirs are investigated to understand water movement during production. Both reservoirs are supported by a huge aquifer and had the same original oil-water contact. The reservoirs are separated by a thick and continuous shale so that the upper sand is categorized as edge water drive and the lower sand as bottomwater drive. Water production was observed at the central up structure wells of the upper sand much earlier than expected. This makes the modeling of water influx complicated because it is difficult to explain this phenomenon only by edge water influx. In this study, a technical study was performed to investigate water influx into the upper sand. A comprehensive review of pressure and production history indicated anomalous higher-pressure areas in the upper sand. Moreover, anomalous temperature profiles were observed in some wells in the same area. At the same time, watered zones were trailed through thermal-neutron decay time(TDT) where a thick water column was observed in the central area of the reservoir. In addition, a three-dimensional (3D) seismic survey has been conducted recently, revealing faults passing through the two reservoirs. Therefore, as a result of data review and subsequent investigation, conductive faults from the lower sand were suspected as supplemental fluid conduits. A pressure transient test was then designed and implemented, which suggested possible leakage from the nearby fault. Interference of the two reservoirs and an estimate of supplemental volume of water influx was made by material balance. Finally, an improved full-scale numerical reservoir model was constructed to model complex water movement, which includes suspected supplemental water from the lower sand. Employment of two kinds of water influx—one a conventional edge water and another a supplemental water invasion from the aquifer of the lowers and through conductive faults—achieved a water breakthrough match. Introduction The Khafji oil field is located in the Arabian Gulf about 40 km offshore Al-Khafji as shown by Fig. 1. The length and width of the field are about 20 and 8 km, respectively. The upper sandstone reservoir, the subject of this study, lies at a depth of about 5,000 ft subsea and was discovered in1960. The average thickness of the reservoir is about 190 ft. The reservoir is of Middle Cretaceous geologic age. Underlying the upper sandstone reservoir is another sandstone reservoir at a depth of about 5,400 ft. It has an average gross thickness of about 650 ft and is separated from the upper sand by a thick shale bed of about 200 ft. Both reservoirs had the same original oil-water contact level as shown by the subsurface reservoir profile in Fig. 2. Both sandstone reservoirs are categorized as strong waterdrive that can maintain reservoir pressure well above the bubblepoint. On the other hand, water production cannot be avoided because of an unfavorable water-to-oil mobility ratio of 2 to 4 and high formation permeability in conjunction with a strong waterdrive mechanism. In a typical edge water drive reservoir, water production normally begins from the peripheral wells located near the oil-water contact and water encroaches as oil production proceeds. However, some production wells located in the central up structure area of the upper sand started to produce formation water before the wells located in the flank area near the water level. In 1996, we started an integrated geological and reservoir study to maximize oil recovery, to enhance reservoir management, and to optimize the production scheme for both sandstone reservoirs. This paper describes a part of the integrated study, which focused on the modeling of water movement in the upper sand. The contents of the study described in this paper are outlined as:diagnosis and description of the reservoir by fully utilizing available data, which include comprehensive review of production history, TDT logs, formation temperatures, pressures, and 3D seismic; introduction of fluid conductive faults as a suspected supplemental water source in the central upstructure area; design and implementation of a pressure transient test to investigate communication between the reservoirs and conductivity of faults; running of material balance for the two reservoirs simultaneously to assess their interference; and construction of an improved full-scale reservoir simulation model and precise modeling of complex water movement. Brief Geological Description of the Upper Sand The structure of the upper sand is anticline with the major axis running northeast to southwest. The structure dip is gentle (Fig. 3) at about3° on the northwestern flank and 2° on the southeastern flank. The upper sand is composed mainly of sandstone-dominated sandstone and shale sequences. It is interpreted that the depositional environment is complex, consisting of shoreface and tide-influenced fluvial channels.
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Woodall, Mark, Grant Skinner, Mauro Viandante, Laura Pontarelli, Konstantinos Kostas, and Elizabeth Haynes. "The role of geosteering in developing the Pyrenees Field." APPEA Journal 54, no. 2 (2014): 494. http://dx.doi.org/10.1071/aj13067.
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The Pyrenees Field comprises a series of biodegraded 19° API oil accumulations reservoired in Early Cretaceous sandstones of the Pyrenees Member in the Exmouth Sub-Basin, offshore WA The reservoir comprises excellent quality, poorly consolidated shallow marine to deltaic sands. Variable thickness oil columns (some with associated gas caps), strong bottom water drive, and relatively viscous oil has necessitated the drilling of long (up to 2,000 m) horizontal wells to maximise reservoir exposure while geosteering well to within a few meters of the roof of the reservoir to maximise standoff from the OWCs. The field is covered by excellent quality 3D seismic data; however, pre-drill mapping for well path planning is complicated by the unconformable nature of the top reservoir boundary formed by the sub-cropping Pyrenees Member. Faulting within and localised velocity variations above the reservoir are also a challenge to pre-drill well planning. Cutting-edge geosteering tools have been used to achieve the desired well paths. The tools use azimuthal deep induction resistivity measurements to model and predict reservoir and fluid boundaries, taking advantage of the large resistivity contrasts between the overlying sealing mudstones of the Muderong Formation and the oil (and occasionally gas) bearing Pyrenees reservoir sands. This extended abstract discusses the application of the tools both in pre-drill well path planning and the real-time geosteering operation. Operations are managed between the rig and a sub-surface team located in a dedicated geosteering room onshore. Here real-time data is compared with planned well paths in 3D seismic and geocellular reservoir models and well path adjustments made to optimise final well placement.
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Evans, N., J. A. MacLeod, N. Macmillan, P. Rorison, and P. Salvador. "The Banff Field, Blocks 22/27a, 29/2a, UK North Sea." Geological Society, London, Memoirs 20, no. 1 (2003): 497–507. http://dx.doi.org/10.1144/gsl.mem.2003.020.01.40.
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AbstractThe Banff Field is an oil field with a small gas cap containing an estimated 300 MMB0 oil-in place. The structure straddles the boundary between blocks 22/27a and 29/2a in the West Central Graben area of UK Central North Sea. The field was discovered by well 29/2a-6 in 1991. Banff Field is a Steeply dipping raft of fractured Late Cretaceous and Danian Chalk on the flank of a salt diapir. Paleocene sands draped over the raft provide addtional reservoir potential. A vertical oil column of over 3000 ft is present within the reservoir sourced from the underlying upper jurassic Kimmeridge Formation shales. Hydrocarbon migration into the trap is believed to have started in the Eocene.The highest reservoir productivity occurs in the Late Cretaceous Tor Formation, which is expected to yield most of the field's reserves. Chalk porosity ranges from 15% to 35% but matrix permeabilities are generally less than 5 mD. Drainage is achieved through extensive faulting and fracturingInitial uncertainties over reservoir performance and connectivity led to a phased development. Phase i comprised a six month Early Production System (EPS), during which time 5 MMBo were produced and the viability of the field was confirmed. Phase 2 Production is by means of a Floating Production System and Offtake (FPSO) Vessel Named the Ramform Banff. First oil production was achieved on 30 January 1999 and ultimate reserves are expected to be in excess of 75 MMBO.
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Abu-Hashish, Mohamed F., Hamdalla A. Wanas, and Emad Madian. "3D geological modeling of the Upper Cretaceous reservoirs in GPT oil field, Abu Sennan area, Western Desert, Egypt." Journal of Petroleum Exploration and Production Technology 10, no. 2 (September 25, 2019): 371–93. http://dx.doi.org/10.1007/s13202-019-00780-9.
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Abstract This study aims to construct 3D geological model using the integration of seismic data with well log data for reservoir characterization and development of the hydrocarbon potentialities of the Upper Cretaceous reservoirs of GPT oil field. 2D seismic data were used to construct the input interpreted horizon grids and fault polygons. The horizon which cut across the wells was used to perform a comprehensive petrophysical analysis. Structural and property modeling was distributed within the constructed 3D grid using different algorithms. The workflow of the 3D geological model comprises mainly the structural and property modeling. The structural model includes fault framework, pillar girding, skeleton girding, horizon modeling and zonation and layering modeling processes. It shows system of different oriented major and minor faults trending in NE–SW direction. The property modeling process was performed to populate the reservoir facies and petrophysical properties (volume of shale (Vsh), fluid saturations (Sw and Sh), total and effective porosities (Φt and Φe), net to gross thickness and permeability) as extracted from the available petrophysical analysis of wells inside the structural model. The model represents a detailed zonation and layering configuration for the Khoman, Abu Roash and Bahariya formations. The 3D geological model helps in the field development and evaluates the hydrocarbon potentialities and optimizes production of the study area. It can be also used to predict reservoir shape and size, lateral continuity and degree of interconnectivity of the reservoir, as well as its internal heterogeneity.
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Pinnock, S. J., and D. M. Dutton. "The Golden Eagle, Peregrine and Solitaire fields, Blocks 14/26a and 20/01, UK North Sea." Geological Society, London, Memoirs 52, no. 1 (2020): 740–54. http://dx.doi.org/10.1144/m52-2017-39.
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AbstractThe Golden Eagle Field is located 18 km north of the Buzzard Field in the Moray Firth, and consists of oil accumulations in the Lower Cretaceous Punt and Upper Jurassic Burns Sandstone members. The development area comprises three fields, Golden Eagle, Peregrine and Solitaire, but up to 90% of the oil-in-place and ultimate recovery are in Golden Eagle. The two satellite fields are primarily structural closures, while the Golden Eagle Field reservoirs have a major element of stratigraphic pinchout. Production commenced in October 2014 and approximately 140 MMbbl of recoverable oil is anticipated over its field life from the 19 development wells (14 producers and 5 injectors) that form the initial development phase. Production performance to date has exceeded expectations, aided through the use of completions that provide zonal control of the reservoir units which has successfully supported reservoir management and improved sweep efficiency.A number of significant lessons have been learned during the early stages of the field life from the integration of dynamic data (real-time downhole fibre-optic reservoir monitoring instruments, inter- and intra-well tracers, and well interference tests) and seismic data improvements (post-start-up acquisition of high-density ocean-bottom node seismic and depth-conversion improvements).
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Al-Ameri, Thamer Khazal, and Riyadh Y. Al-Obaydi. "Cretaceous petroleum system of the Khasib and Tannuma oil reservoir, East Baghdad oil field, Iraq." Arabian Journal of Geosciences 4, no. 5-6 (January 27, 2010): 915–32. http://dx.doi.org/10.1007/s12517-009-0115-4.
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Abu-ElKhir, Hatem, and Sara Hediehd. "Oil Occurrence of Abu Roash Cretaceous Reservoir, Sitra Area, Western Desert, Egypt." Scientific Journal for Damietta Faculty of Science 8, no. 1 (December 1, 2018): 26–32. http://dx.doi.org/10.21608/sjdfs.2018.194799.
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El-Bagoury, Mohamed. "Integrated petrophysical study to validate water saturation from well logs in Bahariya Shaley Sand Reservoirs, case study from Abu Gharadig Basin, Egypt." Journal of Petroleum Exploration and Production Technology 10, no. 8 (August 18, 2020): 3139–55. http://dx.doi.org/10.1007/s13202-020-00969-3.
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Abstract Water saturation is a key parameter in evaluating oil and gas reservoirs and calculating OIIP and GIIP for petroleum fields. The late Cretaceous Bahariya reservoir contains variable amounts of clay minerals. Bore hole logs are affected with those clay minerals particularly the density and resistivity logs. Several methods are acknowledged to determine the true water saturation from well logs in shaley sand reservoirs. Each method assumes a sort of corrections to amount of shale distributed in the reservoir. The scope of this petrophysical study is to integrate core analysis and bore hole logs to investigate the characteristics of water saturation in the Bahariya reservoirs. Comparison between most of the significant shaley sand methods is presented in this research. Reservoir lithology and mineralogy are explained by Elan-model while bore hole images are used for fine-tuning the electrofacies. Siltstone, shaley sand and clean sandstones are the main electrofacies that is characterizing the Bahariya reservoir rocks. For accurate saturation results, some core samples have been used for validating the log-derived water saturation. Dean stark and cation exchange capacity experiments are integrated with bore hole logs to calculate the error in water saturation for each method for best calibration. The successful integration between logs and core measurements led to convenient log evaluation and accurate understanding for the Bahariya reservoir in the prospective part of Abu Gharadig basin.
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Al-Baldawi, Buraq Adnan. "Evaluation of Petrophysical Properties Using Well Logs of Yamama Formation in Abu Amood Oil Field, Southern Iraq." Iraqi Geological Journal 54, no. 1E (May 31, 2021): 67–77. http://dx.doi.org/10.46717/igj.54.1e.6ms-2021-05-27.
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The petrophysical analysis is very important to understand the factors controlling the reservoir quality and production wells. In the current study, the petrophysical evaluation was accomplished to hydrocarbon assessment based on well log data of four wells of Early Cretaceous carbonate reservoir Yamama Formation in Abu-Amood oil field in the southern part of Iraq. The available well logs such as sonic, density, neutron, gamma ray, SP, and resistivity logs for wells AAm-1, AAm-2, AAm-3, and AAm-5 were used to delineate the reservoir characteristics of the Yamama Formation. Lithologic and mineralogic studies were performed using porosity logs combination cross plots such as density vs. neutron cross plot and M-N mineralogy plot. These cross plots show that the Yamama Formation consists mainly of limestone and the essential mineral components are dominantly calcite with small amounts of dolomite. The petrophysical characteristics such as porosity, water and hydrocarbon saturation and bulk water volume were determined and interpreted using Techlog software to carried out and building the full computer processed interpretation for reservoir properties. Based on the petrophysical properties of studied wells, the Yamama Formation is divided into six units; (YB-1, YB-2, YB-3, YC-1, YC-2 and YC-3) separated by dense non porous units (Barrier beds). The units (YB-1, YB-2, YC-2 and YC-3) represent the most important reservoir units and oil-bearing zones because these reservoir units are characterized by good petrophysical properties due to high porosity and low to moderate water saturation. The other units are not reservoirs and not oil-bearing units due to low porosity and high-water saturation.
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Manshad, Abbas Khaksar, Reza Sedighi Pashaki, Jagar A. Ali, Stefan Iglauer, M. Memariani, Majid Akbari, and Alireza Keshavarz. "Geochemical study of the early cretaceous Fahliyan oil reservoir in the northwest Persian Gulf." Journal of Petroleum Exploration and Production Technology 11, no. 6 (May 14, 2021): 2435–47. http://dx.doi.org/10.1007/s13202-021-01178-2.
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AbstractThree crude oil samples from the Fahliyan Formation in ‘KG’ and ‘F’ fields in the northwest Persian Gulf, namely KG-031, F9A-3H and F15-3H for the geochemical study. In this study, the physicochemical properties, gas chromatography (GC, GC Mass) and (Detailed Hydrocarbon Analysis) DHA analyses for the collected Fahliyan oils were carried out. The API, Trace Element (Ni, V) and S% parameters indicated that the Fahliyan oil was generated from a source rock which deposited in reducing environment condition with a carbonate-shale compound lithology. Moreover, low pour point, higher S% and low viscosity parameters of “KG” sample confirmed the existence of medium oil characteristics in this field. In addition, the geochemical outcomes of GC, GC–MS and DHA analyses indicated that the ‘KG’ oils are more aromatic compared with ‘F’ oil; while biomarkers revealed that Fahliyan reservoir oil is highly mature and was formed from a carbonate source rock containing types II, III kerogen. Thus, sterane/hopane biomarkers (C24/C23 and C22/C21 ratios) revealed that Fahliyan oil originated from carbonate source rocks deposited in an anoxic to dysoxic environment, which is consistent with the above analyses. It was identified that the source rock age is early Cretaceous to late Jurassic. It can be reported that the Fahliyan oils from both fields were generated in the same source rock and have almost the same physical properties, and will have the same production strategy.
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Li, Yue, Shi Zhong Ma, and Qi Wang. "Study on Depositional Model of XinMiaoxi-Xinbei Region Fuyu Oil Layer in the Northern Fuxin Uplift of Songliao Basin." Advanced Materials Research 1092-1093 (March 2015): 1470–73. http://dx.doi.org/10.4028/www.scientific.net/amr.1092-1093.1470.
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XinMiaoxi-Xinbei region fuyu reservoir of lower cretaceous quantou forth group sedimentary period develop large shallow-water delta sedimentary, which based on core data and logging information of 44 wells through the analysis of single well facies and logging facies analysis and the research of sedimentary microfacies. This area incude two kinds of subfacies,delta distributary plain,delta front.15 kinds of microfacies such as distributary channel,underwater distributary channel natural levee. Put forward the "source of phase controlled sand", "channel control reservoir" thought, predicted the main development zone of Fuyu reservoir of XinMiaoxi-Xinbei.
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Sayer, Zoë, Jonathan Edet, Rob Gooder, and Alexandra Love. "The Machar Field, Block 23/26a, UK North Sea." Geological Society, London, Memoirs 52, no. 1 (2020): 523–36. http://dx.doi.org/10.1144/m52-2018-45.
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AbstractMachar is one of several diapir fields located in the Eastern Trough of the UK Central North Sea. It contains light oil in fractured Cretaceous–Danian chalk and Paleocene sandstones draped over and around a tall, steeply-dipping salt diapir that had expressed seafloor relief during chalk deposition. The reservoir geology represents a complex interplay of sedimentology and evolving structure, with slope-related redeposition of both the chalk and sandstone reservoirs affecting distribution and reservoir quality. The best reservoir quality occurs in resedimented chalk (debris flows) and high-density turbidite sandstones. Mapping and characterizing the different facies present has been key to reservoir understanding.The field has been developed by water injection, with conventional sweep in the sandstones and imbibition drive in the chalk. Although the chalk has high matrix microporosity, permeability is typically less than 2 mD, and fractures are essential for achieving high flow rates; test permeabilities can be up to 1500 mD. The next phase of development is blowdown, where water injection is stopped and the field allowed to depressurize. This commenced in February 2018.
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Kaufman, R. L., C. S. Kabir, B. Abdul-Rahman, R. Quttainah, H. Dashti, J. M. Pederson, and M. S. Moon. "Characterizing the Greater Burgan Field With Geochemical and Other Field Data." SPE Reservoir Evaluation & Engineering 3, no. 02 (April 1, 2000): 118–26. http://dx.doi.org/10.2118/62516-pa.
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Summary This paper describes recent results from an ongoing geochemical study of the supergiant Greater Burgan field, Kuwait. Oil occurs in a number of vertically separated reservoirs including the Jurassic Marrat reservoir and Cretaceous-Minagish, -Third Burgan, -Fourth Burgan, -Mauddud, and -Wara reservoirs. The Third and Fourth Burgan sands are the most important producing reservoirs. Over 100 oils representing all major producing reservoirs have been analyzed using oil fingerprinting as the principal method, but also supported by gravity, sulfur, and pressure-volume-temperature (PVT) measurements. From a reservoir management perspective, an important feature of the field is the approximately 1,200-ft-long hydrocarbon column which extends across the Burgan and Wara reservoirs. Oil composition varies with depth in this thick oil column. For example, oil gravity varies in a nonlinear fashion from about 10°API near the oil/water contact to about 39°API at the shallowest Wara reservoir. This gravity-depth relationship makes identification of reservoir compartments solely from fluid property data difficult. Including oil geochemistry in the traditional mix of PVT and production logging data improves the understanding of compartmentalization and fluid flow in the reservoir, both in a vertical and lateral sense. The composition of reservoir fluids is controlled by a number of geological and physical processes. We attempted to identify unique sets of geochemical parameters that were sensitive to specific oil alteration processes. One set of geochemical properties correlated strongly with gravity and is, therefore, related to the gravity-segregation process. A second set of parameters showed essentially no correlation with gravity or depth but established unique oil fingerprints for most of the major producing reservoirs and identified a number of different oil groups within the Burgan and Wara reservoirs. We interpret the presence of these oil groups to indicate reservoir compartments owing to laterally continuous shales and faults which act as seals on a geologic time frame. More tentative is the identification of production time frame barriers from the fluid composition data. The oil fingerprint data have been used to distinguish oils from the major producing reservoirs and evaluate hydrocarbon continuity within the reservoirs. Introduction This article describes a geochemical study of oils from the Greater Burgan field, Kuwait. During this study, we examined the compositional variation of oils within the field to evaluate reservoir continuity. This study is part of a larger project to describe the producing characteristics of the major reservoirs in the Burgan field en route to applying the best practices in the overall reservoir management program. In Phase I of this study,1 approximately 60 oils from the Burgan, Magwa, and Ahmadi areas of the Greater Burgan field were analyzed using oil fingerprinting. The objective was to determine if oils from the Wara, Third Burgan, and Fourth Burgan reservoirs had unique oil fingerprints and to evaluate oil mixing because of wellbore communications. In Phase II, a larger suite of wells was sampled to broaden the coverage of the field, both areally and stratigraphically, as shown in Fig. 1. Even though a considerably larger number of wells were sampled in Phase II, the sampling density still remains rather coarse in this supergiant field, spanning 320 sq mile. A variety of different techniques are available for reservoir geochemistry studies.2 The principle method used in this study is whole-oil gas chromatography; sometimes referred to as oil fingerprinting. This method has been described before3 and is, therefore, summarized only briefly here. Oil samples were collected at the wellhead, at atmospheric conditions, and analyzed using capillary gas chromatography. A standard of about 200 calibrated peak heights was developed and from this about 30 standard peak height ratios were calculated. These ratios were selected based on their ability to separate the oils into uniquely different groups. Two different multivariate statistical techniques were used to analyze the chromatography data: cluster analysis and principal components analysis. Both techniques were used to identify groups of similar oils based on the peak height ratios. Petroleum is a very complex natural product whose composition is controlled by various geologic processes which occur both before and after fluid accumulation. In our geochemical studies of the Burgan field, we have used the composition of the produced oil to study the hydrocarbon connectivity of different reservoirs. Some measurements, such as oil gravity, gas/oil ratio and bubblepoint data, characterize the bulk properties of the fluid. Other measurements, such as the hydrocarbon fingerprint, are based on the molecular composition of the fluid. Both types of data are necessary to completely characterize a petroleum reservoir, but the molecular composition data are frequently a more sensitive measure of the reservoir connectivity. Where available, both types of data have been used in this study of the Burgan field. The identification of reservoir compartments, both vertical and lateral, is a necessary component of efficient reservoir appraisal and management. Reservoirs are compartmentalized when barriers to fluid flow are present which prevent fluid communication between different parts of the reservoir. Smalley and Hale have discussed the need for early identification of reservoir compartments well in advance of dynamic production measurements.4 Some barriers are effective on a geologic time scale and frequently result in separate oil pools with unique oil/water contacts and initial pressure gradients. Other barriers may become effective on a production time frame. These are typically identified only after the field is put on production. Reservoir fluid composition data have most frequently been interpreted as indicators of geologic time-frame compartments, but it may provide an early indication of production time-frame compartments in some cases. The Greater Burgan Field The Greater Burgan oil field lies within the Arabian basin in the state of Kuwait. General reviews of the geology and producing history of the field are described by Brennan,5 Kirby et al.,6 and Carman.7 The field is subdivided into the Burgan, Magwa, and Ahmadi sectors based on the presence of three structural domes as shown in Fig. 1. The boundary between the northern Magwa/Ahmadi and the Burgan sectors is the Central Graben fault complex, as shown in Fig. 2.
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Kassab, Mohamed A., Ali El-Said Abbas, Mostafa A. Teama, and Musa A. S. Khalifa. "Prospect evaluation and hydrocarbon potential assessment: the Lower Eocene Facha non-clastic reservoirs, Hakim Oil Field (NC74A), Sirte basin, Libya—a case study." Journal of Petroleum Exploration and Production Technology 10, no. 2 (September 24, 2019): 351–62. http://dx.doi.org/10.1007/s13202-019-00773-8.
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Abstract Petrophysical assessment of Facha Formation based on log data of six wells A1, A3, A4, A5, A8 and A13 recorded over the entire reservoir interval was established. Hakim Oil Field produces from the Lower Eocene Facha reservoir, which is located at the western side of Sirte basin. Limestone, dolostone and dolomitic limestone are the main lithologies of the Facha reservoir. This lithology is defined by neutron porosity—density cross-plot. Noteworthily, limestone increases in the lowermost intervals of the reservoir. Structurally, the field is traversed by three northwest–southeast faults. The shale of the Upper Cretaceous Sirte Formation is thought to be the source rock of the Facha Formation, whereas the seals are the limestone and anhydrite of the Lower Eocene Gir Formation. In this study, the Facha reservoir’s cutoff values were obtained from the cross-plots of the calculated shale volume, porosity and water saturation values accompanied with gamma ray log data and were set as 20%, 10% and 70%, respectively. Isoparametric maps for the thickness variation of net pay, average porosity, shale volume and water saturation were prepared, and the authors found out that the Facha Formation has promising reservoir characteristics in the area of study; a prospective region for oil accumulation trends is in the north and south of the study area.
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Torkington, J., and M. I. Micenko. "A STRATIGRAPHIC ANALYSIS OF THE TALGEBERRY OILFIELD." APPEA Journal 28, no. 1 (1988): 113. http://dx.doi.org/10.1071/aj87011.
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ATP 299P(2) is located in the south-west Queensland portion of the Jurassic Cretaceous Eromanga Basin. Exploration drilling within the permit has resulted in the discovery of several oil pools which are stratigraphically controlled. Appraisal drilling at the Talgeberry Oilfield demonstrated this point when Talgeberry-2, drilled at a structurally higher location, failed to encounter either of the producing sands in Talgeberry-1. Oil is currently being produced from the Wyandra Sandstone and Birkhead Formation in Talgeberry-1 and from the Murta Member in Talgeberry-2.Depositional models are presented for each of the producing reservoirs at the Talgeberry Field, based upon dipmeter interpretation. An integrated seismic stratigraphic study was also undertaken on the Birkhead Formation reservoir.Oil production at Talgeberry is currently confined to distributary channel sands or near-shore distributary mouth bar sands. Distal facies of the distributary mouth bar have been intersected and, while containing oil, have been found to be generally tight.Dipmeter interpretation has proven valuable in determining depositional environment but is limited in defining the a real extent of the reservoir. Seismic-stratigraphic studies are able to define the reservoir geometry better and lead to a more comprehensive understanding of the depositonal environment.
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Gladysheva, Y. I. "Main directions of searching for hydrocarbons in Nadym-Pursk oil and gas region." Oil and Gas Studies, no. 4 (September 9, 2021): 23–31. http://dx.doi.org/10.31660/0445-0108-2021-4-23-31.
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Nadym-Pursk oil and gas region has been one of the main areas for the production of hydrocarbon raw materials since the sixties of the last century. A significant part of hydrocarbon deposits is at the final stage of field development. An increase in gas and oil production is possible subject to the discovery of new fields. The search for new hydrocarbon deposits must be carried out taking into account an integrated research approach, primarily the interpretation of seismic exploration, the creation of geological models of sedimentary basins, the study of geodynamic processes and thermobaric parameters. Statistical analysis of geological parameters of oil and gas bearing complexes revealed that the most promising direction of search are active zones — blocks with the maximum sedimentary section and accumulation rate. In these zones abnormal reservoir pressures and high reservoir temperatures are recorded. The Cretaceous oil and gas megacomplex is one of the main prospecting targets. New discovery of hydrocarbon deposits are associated with both additional exploration of old fields and the search for new prospects on the shelf of the north. An important area of geological exploration is the productive layer of the Lower-Berezovskaya subformation, in which gas deposits were discovered in unconventional reservoirs.
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Osadetz, Kirk G., Andrew Mort, Lloyd R. Snowdon, Donald C. Lawton, Zhuoheng Chen, and Amin Saeedfar. "Western Canada Sedimentary Basin petroleum systems: A working and evolving paradigm." Interpretation 6, no. 2 (May 1, 2018): SE63—SE98. http://dx.doi.org/10.1190/int-2017-0165.1.
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Western Canada Sedimentary Basin (WCSB) crude oil source rocks accumulated typically in “starved” depositional settings of Sloss outer detrital facies belts and lesser stratigraphic cycles. These produced petroleum from marine type II organic matter in response to burial by commonly westward-thickening overlying successions. Oil occurs commonly within the “Sloss” sequence containing its source rock, often up dip from the “petroleum kitchen.” Migration pathways cross stratal contacts, unconformities and structures, and much oil migrated into adjacent sequences, especially into Lower Cretaceous Mannville Group reservoirs. Anaerobic biodegradation affects oil quality and generates secondary biogenic gas. The WCSB oil system paradigm predates the recognition of anaerobic biodegradation. Biodegradation in post-Mannville reservoirs remains underappreciated. Natural gases originate by thermogenic and biogenic mechanisms from kerogens, coals, and crude oils. Gases are variably altered: physically, microbially, and inorganically. Few oil studies addressed solution and associated primary thermogenic or secondary biogenic gas. Gas studies are independent of oil studies and none recognize secondary biogenic gas even in association with biodegraded oils. We hypothesize that secondary biogenic gas occurs commonly, often mixed with other gas, to produce hydrocarbon isotope ratios and variations distinctive from primary biogenic and thermogenic gases. Where Mannville oil pools have sources in underlying marine rocks, Mannville gases are attributed largely to nonmarine sources. Currently, cross-stratal migration is inferred less commonly for gas than for oil. The inference of gas stratigraphic immobility is problematic for biodegradation studies that infer large secondary biogenic gas fluxes into soil and atmospheric sinks, the migration pathways of which pass through Cretaceous strata. In some unconventional plays, gas isotopic “rollover” and “reversal” due to thermal cracking has implications for reservoir performance. Efforts to understand Cordilleran petroleum systems merit investigation to extend unconventional resource plays westward from Interior Platform.
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WHITEHEAD, M., and S. J. PINNOCK. "The Highlander Field, Block 14/20b, UK North Sea." Geological Society, London, Memoirs 14, no. 1 (1991): 323–29. http://dx.doi.org/10.1144/gsl.mem.1991.014.01.40.
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AbstractHighlander Field, discovered in 1976, is a small oil accumulation located 7½ miles northwest of the Tartan Platform and 114 miles northeast of Aberdeen in UK Block 14/20b. The Field lies on the NW-SE-trending Claymore-Highlander Ridge which forms the southern margin of the Witch Ground Graben. Upper Jurassic sandstones of the shallow marine Piper Formation and deeper marine turbidites (the 'Hot Lens Equivalent') within the Kimmeridge Clay Formation form the principal reservoirs. An additional important reservoir occurs within Lower Cretaceous turbidite sandstone and a small crestal accumulation occurs in Carboniferous deltaic sandstone. The structure is a tilted NW-SE-trending fault block downthrown to the northeast. The sandstone reservoirs all dip to the south and southwest and become thin due to onlap or truncation to the north. The Field has a combined structural-stratigraphic trap configuration. Seal is provided by Upper Jurassic siltstone and Lower Cretaceous calcareous clay stone. The accumulations have been sourced from the Kimmeridge Clay Formation in adjacent basins. Eight wells delineate the structure and production is currently 30 000 BOPD. Ultimate recoverable reserves are 70 million barrels of crude oil. Development has been achieved utilizing an innovative remote subsea system, connected to the Tartan Platform 7½ miles to the southeast.
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Hu, Yu Zhao, Pei Rong Zhao, and Yu Hui Lv. "The Petroleum System of Northern Kashi Sag in Tarim Basin and Exploration Direction." Advanced Materials Research 524-527 (May 2012): 89–95. http://dx.doi.org/10.4028/www.scientific.net/amr.524-527.89.
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Northern Kashi Sag is located on the northwestern periphery of Tarim Basin, China. This block has been explored for a half century, and Akmomu gas reservoir was discovered in 2001. In Northern Kashi Sag, organic-rich intervals mainly occur in Carboniferous, Lower Permian and Jurassic. Lower Cretaceous Kezilesu Formation(K1kz) is dominated by braid river succession and is best in big thickness of 385-862m，high porosity of 14.90% and high permeability of 207.00 ×10-3μm2. The first grade cap rocks are gypsolyte and mud-gypsolyte in upper Cretaceous and Paleogene with thickness of 100-200m. Two Petroleum Systems are identified, and one is J2y-N1p, Yangye Formation (J2y) serves as source rock, and Neogene Pakabulake(N1p) as reservoir rock. Another is C1+P1by-K1kz petroleum system, Lower Carboniferous and Lower Permian Biyoulieti Formation( P1by) serve as source rock, and Kezilesu Formation (K1kz) as reservoir rock. J2y-N1p petroleum system contains abundant oil sand resource. In 2001,Akmomu gas reservoir was discovered by AK＃1 in C1+P1by-K1kz petroleum system.
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Gross, M. D. "DETERMINATION OF RESERVOIR DISTRIBUTION OVER THE BLACKBACK/TERAKIHI OIL FIELD, GIPPSLAND BASIN, AUSTRALIA." APPEA Journal 33, no. 1 (1993): 1. http://dx.doi.org/10.1071/aj92001.
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The Blackback/Terakihi oil accumulation is located within the Gippsland Basin permit Vic-P24 on the edge of the present-day continental shelf in water depths ranging from 300 to more than 600 m. Accurate structural mapping, depth conversion and delineation of the reservoir units remain as major uncertainties associated with this oil and gas accumulation. To date three wells, Hapuku-1, Blackback-1 and Terakihi-1 have been drilled on the structure and a 3D seismic survey interpreted.The top of the Latrobe Group structure is a complex erosional remnant somewhat laterally offset from a deep-seated northeast to southwest trending, faulted anticline. Most of the hydrocarbons intersected to date have been encountered within the top of the Latrobe Group closure. All three wells drilled to date have intersected oil at the top of the Latrobe Group in three markedly different reservoir units. These reservoirs range in age from Late Cretaceous to Eocene, with porosity ranging from less than 12 per cent to 26 per cent and permeability from less than 1 md to greater than 3000 md.Given the extreme variation in reservoir quality and the field's location in relatively deep water, delineating the distribution of reservoir units using all available data remains crucial.The generation of seismic attribute maps such as dip, dip azimuth and horizon amplitude slices, calibrated on existing well penetrations has played a major role in delineating a complex reservoir distribution at the top of the Latrobe Group. The calibration of high amplitude seismic events with a high impedance channel infill unit of Eocene age was supported by modelling using SIERRAR modelling software.The integration of existing well control, seismic stratigraphy and fault geometry together with seismic attribute mapping and modelling has resulted in a more tightly constrained estimate of the field reserves.
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Tang, Hong, Niall Toomey, and W. Scott Meddaugh. "Using an Artificial-Neural-Network Method To Predict Carbonate Well Log Facies Successfully." SPE Reservoir Evaluation & Engineering 14, no. 01 (February 21, 2011): 35–44. http://dx.doi.org/10.2118/123988-pa.
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Summary The Maastrichtian (Upper Cretaceous) reservoir is one of five prolific oil reservoirs in the giant Wafra oil field. The Maastrichtian oil production is largely from subtidal dolomites at an average depth of 2,500 ft. Carbonate deposition occurred on a very gently dipping, shallow, arid, and restricted ramp setting that transitioned between normal marine conditions to restricted lagoonal environments. The average porosity of the reservoir interval is approximately 15%, although productive zones have porosity values up to 30–40%. The average permeability of the reservoir interval is approximately 30 md. Individual core plugs have measured permeability up to 1,200 md. Efforts to predict sedimentary facies from well logs in carbonate reservoirs is difficult because of the complex carbonate sedimentary facies structures, strong diagenetic overprint, and challenging log analysis in part owing to the presence of vugs and fractures. In the study, a workflow including (1) core description preprocessing, (2) log- and core-data cleanup, and (3) probabilistic-neural-network (PNN) facies analysis was used to predict facies from log data accurately. After evaluation of a variety of statistical approaches, a PNN-based approach was used to predict facies from well-log data. The PNN was selected as a tool because it has the capability to delineate complex nonlinear relationships between facies and log data. The PNN method was shown to outperform multivariate statistical algorithms and, in this study, gave good prediction accuracy (above 70%). The prediction uncertainty was quantified by two probabilistic logs—discriminant ability and overall confidence. These probabilistic logs can be used to evaluate the prediction uncertainty during interpretation. Lithofacies were predicted for 15 key wells in the Wafra Maastrichtian reservoir and were effectively used to extend the understanding of the Maastrichtian stratigraphy, depositional setting, and facies distribution.
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Srivastava, Raj K., Sam S. Huang, and Mingzhe Dong. "Comparative Effectiveness of CO2 Produced Gas, and Flue Gas for Enhanced Heavy-Oil Recovery." SPE Reservoir Evaluation & Engineering 2, no. 03 (June 1, 1999): 238–47. http://dx.doi.org/10.2118/56857-pa.
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Summary A large number of heavy oil reservoirs in Canada and in other parts of the world are thin and marginal and thus unsuited for thermal recovery methods. Immiscible gas displacement appears to be a very promising enhanced oil recovery technique for these reservoirs. This paper discusses results of a laboratory investigation, including pressure/volume/temperature (PVT) studies and coreflood experiments, for assessing the suitability and effectiveness of three injection gases for heavy-oil recovery. The gases investigated were a flue gas (containing 15 mol % CO2 in N2), a produced gas (containing 15 mol?% CO2 in CH4), and pure CO2 . The test heavy-oil (14° API gravity) was collected from Senlac reservoir located in the Lloydminster area, Saskatchewan, Canada. PVT studies indicated that the important mechanism for Senlac oil recovery by gas injection was mainly oil viscosity reduction. Pure CO2 appeared to be the best recovery agent, followed by the produced gas. The coreflood results confirmed these findings. Nevertheless, produced gas and flue gas could be sufficiently effective flooding agents. Comparable oil recoveries in flue gas or produced gas runs were believed to be a combined result of two competing mechanisms—a free-gas mechanism provided by N2 or CH4 and a solubilization mechanism provided by CO2. This latter predominates in CO2 floods. Introduction A sizable number of heavy-oil reservoirs in Canada1 and in other parts of the world are thin and shaly. Some of these reservoirs are also characterized by low-oil saturation, heterogeneity, low permeability, and bottom water.2,3 For example, about 55% of 1.7 billion m3 of proven heavy-oil resource in the Lloydminster and Kindersley region in Saskatchewan, Canada, is contained in less than 5 m (15 ft.) pay zone and nearly 97% is in less than 10 m (30 ft.) pay zone.4,5 Primary and secondary methods combined recover only about 7% of the proven initial oil in place (IOIP).1 Such reservoirs are not amenable to thermal recovery methods: heat is lost excessively to surroundings and steam is scavenged by bottomwater zones.6,7 The immiscible gas displacement appears to be a very promising enhanced oil recovery (EOR) process for these thin reservoirs. The immiscible gas EOR process has the potential to access more than 90% of the total IOIP.1,7 It could, according to previous studies,6–12 recover up to an additional 30% IOIP incremental over that recovered by initial waterflood for some moderately viscous oils. For the development of a viable immiscible gas process applicable to moderately viscous heavy oils found in this sort of reservoirs, we selected three injection gases for study: CO2 reservoir-produced gas (RPG), and flue gas (FG) from power plant exhausts. Extensive literature is available on CO2 flooding for heavy-oil recovery, dealing with pressure/volume/temperature (PVT) behavior,3,6,7,13-15 oil recovery characteristics from linear and scaled models,3,6-8,10-12,15,16 numerical simulation, and field performance.17–19 However, only limited data are available on flue gas and produced gas flooding.20–22 To determine the most suitable gas for EOR application from laboratory investigations, we need knowledge of the physical and chemical interaction between gas, reservoir oil, and formation rock; and information on the recovery potential for various injection gases for a targeted oil. The test oil selected for this study was from the Senlac reservoir (14° API) located in northwest Saskatchewan (Lloydminster area). The PVT properties for the oil/injection gas mixtures were measured and compared. A comparative study of the oil recovery behavior for Senlac dead oil and Senlac reservoir fluid was carried out with different injection gases to assess their relative effectiveness for EOR. Senlac Reservoir Geology The Senlac oil pool is located within the lower Cretaceous sand/shale sequence of the Mannville Group. The Mannville thickens northward and lies unconformably on the Upper Devonian Carbonates of the Saskatchewan Group. The trapping mechanism for the oil is mainly stratigraphic. The lower Lloydminster oil reservoir is a wavy, laminated, very fine- to fine-grained, well sorted, and generally unconsolidated sandstone. It exhibits uniform dark oil staining throughout, interrupted by a number of shale beds of 2 to 9 m (6 to 27 ft) thick, which are distributed over the entire reservoir. The reservoir is overlain by a shale/siltstone/sandstone sequence and lies on a 3 m (9 ft) thick coal seam. The detailed reservoir (Senlac) data and operating characteristics are provided in Ref. 5. The reservoir temperature is 28°C (82.4°F) and the reservoir pressure varies between 2.5 and 4.1 MPa (363 and 595 psia). The virgin pressure of the reservoir at discovery was 5.4 MPa (783 psia) and the gas/oil ratio (GOR) was 16.2 sm3/m3 (89.8 sft3 /bbl). The reservoir matrix has a porosity of about 27.7% by volume and permeability of about 2.5 mD. The average water saturation is about 32% pore volume (PV). The pattern configuration for oil production is five-spot on a 16.2 ha (40 acre) drainage area. The estimated primary and secondary (solution gas and waterflood) recovery is 5.5% of the initial oil in place. Experiment Wellhead Dead Oil and Brine. Senlac wellhead dead oil and formation brine (from Well 16-35-38-27 W3M) were supplied by Wascana Energy, Inc. The oil was cleaned for the experiments by removal of basic sediment and water (BS&W) through high-speed centrifugation. The chemical and physical properties of cleaned Senlac stock tank oil are shown in Table 1. The formation brine was vacuum filtered twice to remove iron contamination from the sample barrels.
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Trewin, Nigel H., and Mark G. Bramwell. "The Auk Field, Block 30/16, UK North Sea." Geological Society, London, Memoirs 14, no. 1 (1991): 227–36. http://dx.doi.org/10.1144/gsl.mem.1991.014.01.28.
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AbstractThe Auk field is located in Block 30/16 at the western margin of the Central Graben. Oil is contained in a combination stratigraphic and structural trap which is sealed by Cretaceous chalk and Tertiary claystones. An oil column of up to 400 ft is contained within Rotliegend sandstones, Zechstein dolomites, Lower Cretaceous breccia and Upper Cretaceous chalk. Production has taken place since 1975 with 80% coming from the Zechstein, in which the best reservoir lithology is a vuggy fractured dolomite where porosity is entirely secondary due to the dolomitization process and leaching of evaporites. Both Rotliegend dune slipface sandstones, and the Lower Cretaceous breccia comprising porous Zechstein clasts in a sandy matrix, also contribute to production. Poor seismic definition of the reservoir results in reliance on well control for detailed reservoir definition. The field has an estimated ultimate recovery of 93 MMBBL with 13 MMBBL remaining at the end of 1988.The Auk field is situated in Block 30/16 of the Central North Sea about 270 km ESE from Aberdeen in 240-270 ft of water (Fig. 1). The field covers an area of about 65 km2 and is a combination of tilted horst blocks and stratigraphic traps, located at the western margin of the South West Central Graben. The Auk horst is about 20 km long and 6-8 km wide, with a NNW-SSE trend. It is bounded on the west by a series of faults with throws of up to 1000 ft, and the eastern boundary fault has a throw of 5000 ft in the north reducing to zero in the south (Fig. 2). The horst is a westward tilted fault block in the north which grades into a faulted anticline in the south. The Auk accumulation is largely contained within Zechstein dolomites and is ultimately sealed by Cretaceous chalk which overlies the base Cretaceous erosion surface. An E-W cross-section of the field is illustrated by Fig. 3. Auk was the first of the alphabetical sequence of North Sea sea-bird names used for Shell/ Esso fields.
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Lisk, M., J. Ostby, N. J. Russell, and G. W. O’Brien. "OIL MIGRATION HISTORY OF THE OFFSHORE CANNING BASIN." APPEA Journal 40, no. 2 (2000): 133. http://dx.doi.org/10.1071/aj99069.
Full textAbstract:
The dual issues of the presence or absence of a viable, oil-prone petroleum system and reservoir quality represent key exploration uncertainties in the lightly explored Offshore Canning Basin, North West Shelf. To better quantify these factors, a detailed fluid inclusion investigation of potential reservoir horizons within the basin has been undertaken. The results have been integrated with regional petroleum geology and Synthetic Aperture Radar (SAR) oil seep data to better understand the oil migration risk in the region.The fluid inclusion data provide confirmation of widespread oil migration at multiple Mesozoic and Palaeozoic levels, including those wells that are remote from the likely source kitchens. The lack of evidence for present or palaeo-oil accumulations is consistent with the proposition that none of the currently water-wet wells appear to have tested a valid structure. These observations, when combined with the presence of numerous direct hydrocarbon indicators on seismic data and a number of oil slicks (from SAR data) at the basin’s edge, suggest that the potential for oil charge to valid structures is much higher than previously recognised.Petrographic analysis of the tight, gas-bearing, Triassic sandstones in Phoenix–1 suggests that the low porosity and permeability is the result of late poikilotopic carbonate cement. Significantly, the presence of oil inclusions within quartz overgrowths that pre-date the carbonate indicates that oil migration began prior to crystallisation of carbonate. Fluid inclusion palaeotemperatures combined with a 1D basin model suggest that trapping of oil as inclusions occurred in the Early to Middle Cretaceous and that predictions of reservoir quality using available water-wet wells could seriously under-estimate porositypermeability levels in potential traps that were charged with oil at about 100 Ma. Indeed, acid leaching of core plugs from Phoenix–1 indicates that removal of diagenetic carbonate results in significant permeability increase with obvious implications for the producibility of any future oil discovery. Further, evidence of Early Cretaceous oil charge has implications for the size and locality of source kitchens compared to that observed at the current day.Collectively, the data indicate the area has received widespread oil migration and suggest future exploration, even to relatively deep levels, may be successful if valid traps can be delineated.
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Hart, Bruce. "Stratigraphy and hydrocarbon resources of the San Juan Basin: Lessons for other basins, lessons from other basins." Mountain Geologist 58, no. 2 (April 1, 2021): 43–103. http://dx.doi.org/10.31582/rmag.mg.58.2.43.
Full textAbstract:
This paper examines the relationships between stratigraphy and hydrocarbon production from the San Juan Basin of New Mexico and Colorado. Abundant data and the long production history allow lessons to be learned, both from an exploration and development perspective, that can be applied in other basins. Conversely, as new play types and technologies are defined and developed elsewhere, the applicability of those tools in the San Juan Basin needs to be understood for well-informed exploration and development activities to continue. The San Juan Basin is a Latest Cretaceous – Tertiary (Paleogene) structure that contains rocks deposited from the Lower Paleozoic to the Tertiary, but only the Upper Cretaceous section has significant hydrocarbon, mostly gas, production. Herein I make the case for studying depositional systems, and the controls thereon (e.g., basin development, eustasy, sediment supply), because they are the first-order controls on whether a sedimentary basin can become a hydrocarbon province, or super basin as the San Juan Basin has recently been defined. Only in the Upper Cretaceous did a suitable combination of forcing mechanisms combine to form source and reservoir rocks, and repeated transgressive-regressive cycles of the Upper Cretaceous stacked multiple successions of source and reservoir rocks in a way that leads to stacked pay potential. Because of the types of depositional systems that could develop, the source rocks were primarily gas prone, like those of other Rocky Mountain basins. Oil-prone source rocks are present but primarily restricted to episodes of peak transgression. A lack of suitable trapping mechanisms helps to explain the relative dearth of conventional oil pools. Although gas production has dropped precipitously in the past decade, driven primarily by overabundance of gas supply associated with the shale-gas boom, the combination of horizontal drilling and multi-stage hydraulic fracturing is being applied to revive oil production from some unconventional stratigraphic targets with success.
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Abramovitz, Tanni. "Geophysical imaging of porosity variations in the Danish North Sea chalk." Geological Survey of Denmark and Greenland (GEUS) Bulletin 15 (July 10, 2008): 17–20. http://dx.doi.org/10.34194/geusb.v15.5033.
Full textAbstract:
More than 80% of the present-day oil and gas production in the Danish part of the North Sea is extracted from fields with chalk reservoirs of late Cretaceous (Maastrichtian) and early Paleocene (Danian) ages (Fig. 1). Seismic reflection and in- version data play a fundamental role in mapping and characterisation of intra-chalk structures and reservoir properties of the Chalk Group in the North Sea. The aim of seismic inversion is to transform seismic reflection data into quantitative rock properties such as acoustic impedance (AI) that provides information on reservoir properties enabling identification of porosity anomalies that may constitute potential reservoir compartments. Petrophysical analyses of well log data have shown a relationship between AI and porosity. Hence, AI variations can be transformed into porosity variations and used to support detailed interpretations of porous chalk units of possible reservoir quality. This paper presents an example of how the chalk team at the Geological Survey of Denmark and Greenland (GEUS) integrates geological, geophysical and petrophysical information, such as core data, well log data, seismic 3-D reflection and AI data, when assessing the hydrocarbon prospectivity of chalk fields.