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1
An, P., W. M. Moon, and F. Kalantzis. "Reservoir characterization using seismic waveform and feedforword neural networks." GEOPHYSICS 66, no. 5 (September 2001): 1450–56. http://dx.doi.org/10.1190/1.1487090.
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Feedforward neural networks are used to estimate reservoir properties. The neural networks are trained with known reservoir properties from well log data and seismic waveforms at well locations. The trained neural networks are then applied to the whole seismic survey to generate a map of the predicted reservoir property. Both theoretical analysis and testing with synthetic models show that the neural networks are adaptive to coherent noise and that random noise in the training samples may increase the robustness of the trained neural networks. This approach was applied to a mature oil field to explore for Devonian reef‐edge oil by estimating the product of porosity and net pay thickness in northern Alberta, Canada. The resulting prediction map was used to select new well locations and design horizontal well trajectories. Four wells were drilled based on the prediction; all were successful. This increased production of the oil field by about 20%.
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ALhakeem, Naseem Sh, Medhat E. Nasser, and Ghazi H. AL-Sharaa. "3D Geological Modeling for Yamama Reservoir in Subba, Luhias and Ratawi Oil Fields, South of Iraq." Iraqi Journal of Science 60, no. 5 (May 26, 2019): 1023–36. http://dx.doi.org/10.24996/ijs.2019.60.5.12.
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3D geological model for each reservoir unit comprising the Yamama Formation revealed to that the formation is composed of alternating reservoirs and barriers. In Subba and Luhais fields the formation began with barrier YB-1 and four more barriers (YB-2, YB-3, YB-4, YB-5), separated five reservoirs (YR-A, YR-B, YR-C, YR-D, YR-E) ranging in thickness from 70 to 80 m for each of them deposited by five sedimentary cycles. In the Ratawi field the formation was divided into three reservoir units (YR-A, YR-B, and YR-C) separated by two barrier units (YB-2 and YB-3), the first cycle is missing in Ratawi field.
The study involves 1 well in Luhais field (Lu-12), 3 wells in Subba field (Su-7, Su-8, and Su-9), and 5 wells in Ratawi field (Rt-3, Rt-4, Rt-5, Rt-6 and Rt-7), the Luhais, Subba, and Ratawi fields located in the Mesopotamia zone (Zubair subzone).
The reservoir units (YR-C and YR-D) in Subba oil field, and YR-B in Ratawi oil field represent the major reservoir units that characterized by the best Petrophysical properties (the highest porosity, the lowest water saturation, and the best Net Pay Thickness), Luhais oil field has poor to moderate Petrophysical properties and low oil bearing in YR-A, YR-B and YR-C units, and produce heavy oil and salt water from YR-D and YR-E as indicated by low resistivity log reading, and according to the Drill Steam Test (DST) with the description of cutting in final geological reports.
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Sarhan, Mohammad Abdelfattah. "Petrophysical characterization for Thebes and Mutulla reservoirs in Rabeh East Field, Gulf of Suez Basin, via well logging interpretation." Journal of Petroleum Exploration and Production Technology 11, no. 10 (September 6, 2021): 3699–712. http://dx.doi.org/10.1007/s13202-021-01288-x.
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AbstractThe current work assesses the sandstones of the Mutulla Formation as well as the limestone of the Thebes Formation for being promising new oil reservoirs in Rabeh East field at the southern portion of the Gulf of Suez Basin. This assessment has been achieved through petrophysical evaluation of wireline logs for three wells (RE-8, RE-22 and RE-25). The visual analysis of well logs data revealed that RE-25 Well is the only well demonstrating positive criteria in five zones for being potential oil reservoirs. The favourable zone within Thebes Formation locates between depths 5084 ft and 5100 ft (Zone A). However, the other positive zones in Mutulla Formation occur between depths: 5403.5–5413.5 ft (Zone B), 5425.5–5436 ft (Zone C), 5488–5498 ft (Zone D) and 5558.5–5563.5 ft (Zone E). The quantitative evaluation shows that the Zone A of Thebes Formation is the best oil-bearing zone in RE-25 Well in terms of reservoir quality since it exhibits lowest shale volume (0.07), minimum water saturation (0.23) and lowest bulk volume of water (0.03). These limestone beds include type of secondary porosity beside the existing primary porosity. On the other hand, the sandstones of Mutulla Formation in RE-25 contain four reservoir zones (B, C, D and E) with the total net pay thickness of 35.5 ft. Moreover, the obtained results revealed that it is expected for zones B, C and D to produce oil without water but Zone E will produce oil with water.
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Vargo, Jay, Jim Turner, Vergnani Bob, Malcolm J. Pitts, Kon Wyatt, Harry Surkalo, and David Patterson. "Alkaline-Surfactant-Polymer Flooding of the Cambridge Minnelusa Field." SPE Reservoir Evaluation & Engineering 3, no. 06 (December 1, 2000): 552–58. http://dx.doi.org/10.2118/68285-pa.
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Summary The Cambridge Minnelusa field alkaline-surfactant-polymer (ASP) flood was an economic and technical success, with ultimate incremental oil of 1,143,000 bbl at a cost of $2.42 per barrel. This success was due to an integrated approach of the application, including: reservoir engineering and geologic studies, laboratory chemical system design, numerical simulation, facilities design, and ongoing monitoring. This paper discusses how each of these was used in the design and evaluation of the Cambridge ASP project. Introduction The purpose of the alkaline-surfactant-polymer technology is to produce incremental oil by reducing the waterflood residual oil saturation. The technology combines interfacial tension-reducing chemicals (alkali and surfactant) with a mobility control chemical (polymer). The interfacial tension reducing chemicals minimize the capillary forces that trap waterflood residual oil while the mobility control chemical improves reservoir contact and flood efficiency. The first alkaline-surfactant-polymer project was performed in a nearby Minnelusa field.1,2 Other alkaline-surfactant-polymer projects include a pilot in an Oklahoma field,3 and three in People's Republic of China oil fields.4–9 Lessons learned from these projects and applied to the Cambridge alkaline-surfactant-polymer project are: good mobility control is essential for a successful project; a detailed study of the reservoir including geology, reservoir engineering, laboratory fluid design, and numerical simulation improve the probability of success; injection facilities must mix the injected solution according to the design parameters for a successful project; and attention to detail, including quality control of injected materials and scheduled maintenance of injection and mixing equipment, is important. The Cambridge field, located in Section 28 of Township 53N and Range 68W in Crook County, Wyoming, is operated by Plains Petroleum Operating Co., a subsidiary of Barrett Resources Corp. The field produces 31 cp, 20° API gravity crude oil from the Permian Minnelusa upper "B" sand at 2139 m [7,108 ft]. The reservoir temperature is 55.6°C [132°F] and the average thickness is 8.75 m [28.7 ft]. The crude oil formation volume factor is 1.03 with a bubblepoint of 586 kPa [85 psi]. The average porosity and permeability are 18% and 0.834 µm2 [845 md], respectively. Connate water saturation was 31.6% with an initial reservoir pressure of 12 355 kPa [1792 psi]. Field History The Cambridge field is defined as 1 131 500 m3 [7,117 Mbbl] pore volume with 795 000 STm3 [4,875 MSTB] of original oil in place. The field was discovered by McAdams, Roux, and Associates in 1989 with the MRA Federal 31-28. All subsequent drilling locations were based on three-dimensional (3D) seismic data. Peak primary oil production was 77.7 m3/d [489 BOPD]. Within a year, the production rate declined to 5.9 m3/d [37 BOPD], as is typical of Minnelusa reservoirs. The producing mechanism is fluid and rock expansion with the initial gas-oil ratio (GOR) being essentially zero. The Federal 21-28 and 32-28 began production in June 1990 with peak production of 11.0 and 46.4 m3/d [69 and 292 BOPD], respectively. Federal 23-28 started production in October 1990 with peak production occurring in November 1990 of 33.7 m3/d [212 BOPD] of oil and 2.9 m3/d [18 BWPD] of water. Primary production was 34 600 m3 [217.7 Mbbl] oil and 3800 m3 [23.3 Mbbl] water from December 1989 to January 1993. Water injection began in January 1993 with the conversion of the Federal 32-28. Alkaline-surfactant-polymer solution injection started one month later in February 1993. Therefore, the alkaline-surfactant-polymer process was applied as a secondary flood. As a result, operating costs are not duplicated by running a waterflood followed by an alkaline-surfactant-polymer flood. The polymer drive solution began injection in October 1996 with the final water drive beginning in May 2000. The chemical injection sequence was: 30.7% Vp of alkaline-surfactant-polymer solution followed by 29.7% Vp of polymer drive solution followed by water to the economic limit. Percent pore volume is based on swept area pore volume. Swept area is defined as the volume of reservoir contacted by the injected fluid and is approximately 82% of the total pore volume for the Cambridge field. Swept area injected volume and oil recovery calculations are more comparable to radial coreflood results than total field values. For reservoirs like the Minnelusa in which well placement is limited by reservoir geometry, comparison of total field calculations can be misleading. Differences in total field calculations are often dictated by reservoir contact inefficiency and not process efficiency. When this condition exists, swept area calculation is a better comparison to delineate accurately the economic injected chemical volumes and oil recovery. 10 The calculated swept area pore volume is 926 400 m 3 [5,827 Mbbl] and the original oil in place is 647 300 m3 [4,071.8 Mbbl]. Interpretation of 3D seismic data resulted in the drilling of the Federal 41A-28 in November 1994 and the Federal 33-28 in February 1996. Federal 41A-28 was produced through March 1996 and Federal 33-28 was produced through October 1998. Geologic Description The Cambridge field is on the eastern flank of the Powder River basin and produces oil from the Permian Minnelusa upper B sandstone. The Minnelusa formation is unconformably overlain in this area by the Opeche siltstone member of the Permian Goose Egg formation, which in turn is overlain by the regional Minnekahta limestone, also a member of the Goose Egg formation. The Minnelusa vertical sequence consists of alternating carbonates and sandstones. The Minnelusa upper B reservoir is a friable, Eolian sandstone with modest amounts of dolomite and anhydrite cement and is a preserved remnant of a highly dissected coastal dune complex. Dolomite and anhydrite cement are the main chemical adsorbing sites of the Cambridge sand. Fig. 1 depicts the field's net-pay isopach. The reservoir dips approximately 1.7° to the southwest. A water-oil contact controls the field's producing limit on the southwest. Dystra-Parsons is 0.57. Preferential flow of injected fluids follows an axis along Wells 41A-28 and 21-28. The 3D seismic indicates the sand thins between Wells 33-28 and 23-28.
5
Neff, Dennis B. "Amplitude map analysis using forward modeling in sandstone and carbonate reservoirs." GEOPHYSICS 58, no. 10 (October 1993): 1428–41. http://dx.doi.org/10.1190/1.1443358.
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The extent to which seismic amplitude maps can contribute to the analysis of hydrocarbon reservoirs was investigated for clastic and carbonate reservoirs worldwide. By using a petrophysical‐based, forward modeling process called incremental pay thickness (IPT) modeling, five lithology types were quantitatively analyzed for the interplay of seismic amplitude versus lithology, porosity, hydrocarbon pore fluid saturation, bedding geometries, and reservoir thickness. The studies identified three common tuning curve shapes (concave, convex, and bilinear) that were primarily dependent upon the lithology model type and the average net porosity therein. While the reliability of pay and porosity predictions from amplitude maps varied for each model type, all analyses showed a limited thickness range for which amplitude data could successfully predict net porosity thickness or hydrocarbon pore volume. The investigation showed that systematic forward modeling is required before amplitude maps can be properly interpreted.
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Neff, Dennis B. "Incremental pay thickness modeling of hydrocarbon reservoirs." GEOPHYSICS 55, no. 5 (May 1990): 556–66. http://dx.doi.org/10.1190/1.1442867.
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The one-dimensional convolution model or synthetic seismogram provides more information about the seismic waveform expression of hydrocarbon reservoirs when petrophysical data (porosity, shale volume, water saturation, etc.) are systematically integrated into the seismogram generation process. Use of this modeling technique, herein called Incremental Pay Thickness (IPT) modeling, has provided valuable insights concerning the seismic response of several offshore Gulf of Mexico amplitude anomalies. Through integration of the petrophysical data, comparisons between seismic waveform response and expected reservoir pay thickness are extended to include estimates of gross pay thickness, net pay thickness, net porosity feet of pay, and hydrocarbons in place. These 1-D synthetic data easily convert to 2-D displays that often show exceptional waveform correlations between the synthetic and actual seismic data. Anomalous observed waveform responses include complex tuning curves; diagnostic isochron measurements even in unresolved thin-bed reservoirs; and extreme variations in the seismic expression of hydro-carbon-fluid contacts. While IPT modeling examples illustrate both the variability and nonuniqueness of seismic responses to hydrocarbon reservoirs, they often show good seismic predictability of pay thickness if the appropriate choice of amplitude-isochron versus pay thickness is made (i.e., peak amplitude, trough amplitude, or average amplitude versus gross pay thickness, net pay thickness, net porosity feet of pay, or hydrocarbons in place).
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Alabeed, Adel, Zeyad Ibrahim, and Emhemed Alfandi. "DETERMINATION CONVENTIONAL ROCK PROPERTIES FROM LOG DATA & CORE DATA FOR UPPER NUBIAN SANDSTONE FORMATION OF ABU ATTIFEL FIELD." Scientific Journal of Applied Sciences of Sabratha University 2, no. 1 (April 25, 2019): 29–37. http://dx.doi.org/10.47891/sabujas.v2i1.29-37.
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A reservoir is a subsurface rock that has effective porosity and permeability which usually contains commercially exploitable quantity of hydrocarbon. Reservoir characterization is undertaken to determine its capability to both store and transmit fluid. Petrophysical well log and core data, in this paper, were integrated in an analysis of the reservoir characteristics by selecting of three productive wells. The selected wells are located at Abu Attifel field in Libya for Upper Nubian Sandstone formation at depth varied form 12921 to14330 ft. The main aim of this study is to compare the laboratory measurement of core data with that obtained from well log data in order to determine reservoir properties such as shale volume, porosity (Φ), permeability (K), fluid saturation, net pay thickness. The plots of porosity logs and core porosity versus depth for the three wells revealed significant similarity in the porosity values. The average volume of shale for the reservoir was determined to be 22.5%, and average permeability values of the three wells are above 150 md, while porosity values ranged from 9 to 11%. Low water saturation 13 to 22% in the three wells indicates the wettability of the reservoir is water-wet.
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Neff, Dennis B. "Estimated pay mapping using three‐dimensional seismic data and incremental pay thickness modeling." GEOPHYSICS 55, no. 5 (May 1990): 567–75. http://dx.doi.org/10.1190/1.1442868.
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Better estimates of hydrocarbon pay thickness and reservoir distribution are achieved if forward modeling is combined with crossplot cluster analysis before the seismic amplitude and isochron data are converted into estimates of pay thickness. To facilitate this process, an enhanced convolutional modeling technique that incorporates petrophysical data and equations into the synthetic seismogram generation process was developed. These incremental pay thickness (IPT) forward models provide the pertinent seismic and petrophysical values required for crossplot analysis. The crossplot analyses then define which seismic variables (trough amplitude, peak amplitude, time structure, isochron, etc.) are most uniquely related to a pay thickness parameter (gross thickness, net thickness, net porosity thickness, or hydrocarbons in place). Work to date, mostly in offshore Gulf Coast gas sands, has shown significant variation in the crossplot transforms required to convert seismic data to estimated pay maps. As such, an interactive, model‐based, interpretive approach is recommended as an appropriate means to integrate petrophysical, geologic, and 3-D seismic data in the creation of reservoir pay maps.
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Li, Yandong, Xiaodong Zheng, and Yan Zhang. "High-frequency anomalies in carbonate reservoir characterization using spectral decomposition." GEOPHYSICS 76, no. 3 (May 2011): V47—V57. http://dx.doi.org/10.1190/1.3554383.
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Low-frequency shadows have often been used as hydrocarbon indicators in the application of spectral decomposition. The reason behind the low-frequency anomaly has been explained as high-frequency energy attenuation caused by hydrocarbons. However, in our practice on carbonate reservoir characterization in two areas, Precaspian Basin and Central Tarim Basin, China, we encountered high-frequency anomalies, i.e., the isofrequency slices or sections at high frequencies exhibit anomalies associated with the good carbonate reservoir, particularly in the tight limestone background. We used the product of porosity and thickness as a parameter to measure the quality of the carbonate reservoir of each well and classified the 46 wells in our two studied areas into three types. Type I wells contain high-porosity thick reservoirs, type II wells contain reservoirs with moderate porosity and thickness, and type III wells contain only low-porosity thin reservoirs. The results were that 12 out of 13 type I wells exhibit high-frequency anomalies, and 30 out of 33 type II and type III wells do not exhibit high-frequency anomalies. We further validated the existence of this high-frequency anomaly by forward modeling analysis and fluid substitution experiments using the actual well-log curves measured in the carbonate reservoir. The results showed that in our two studied areas the high-frequency anomalies are more common than low-frequency shadows that can be observed only when the thickness of the reservoir is more than half of the wavelength or the reservoir rocks are extremely unconsolidated. Therefore, this high-frequency anomaly may be used as a more reliable indicator for a good carbonate reservoir than low-frequency shadows in real applications.
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Yar, Mustafa, Syed Waqas Haider, Ghulam Nabi, Muhammad Tufail, and Sajid Rahman. "Reservoir Characterization of Sand Intervals of Lower Goru Formation Using Petrophysical Studies; A Case Study of Zaur-03 Well, Badin Block, Pakistan." International Journal of Economic and Environmental Geology 10, no. 3 (November 14, 2019): 118–24. http://dx.doi.org/10.46660/ijeeg.vol10.iss3.2019.320.
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Present study deals with petrophysical interpretation of Zaur-03 well for reservoir characterization of sandintervals of Lower Goru Formation in Badin Block, Southern Indus Basin, Pakistan. Early Cretaceous Lower GoruFormation is the distinct reservoir that is producing hydrocarbons for two decades. Complete suite of wireline logsincluding GR log, Caliper log, SP log, Resistivity logs (MSFL, LLS, LLD), Neutron log and Density log along withwell tops and complete drilling parameters were analyzed in this study. The prime objective of this study was to markzones of interest that could act as reservoir and to evaluate reservoir properties including shale volume (Vsh), porosity(ϕ), water saturation (Sw), hydrocarbon saturation (Sh) and net pay thickness. Based on Petrophysical evaluation threezones have been marked in Lower Goru Formation, A Sand (1890m to 1930m), B-sand (1935m to 2010) and C-sand(2015m to 2100m). The average calculated parameters for evaluation of reservoir properties of Zaur-03 well depicts anaverage porosity of 8.92% and effective porosity of 4.81%. Water Saturation is calculated as 28.54% and HydrocarbonsSaturation is 71.46%. Analysis shows that Sh in Zaur-03 well is high so the production of hydrocarbons iseconomically feasible.
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Yar, Mustafa, Syed Waqas Haider, Ghulam Nabi, Muhammad Tufail, and Sajid Rahman. "Reservoir Characterization of Sand Intervals of Lower Goru Formation Using Petrophysical Studies; A Case Study of Zaur-03 Well, Badin Block, Pakistan." International Journal of Economic and Environmental Geology 10, no. 3 (November 14, 2019): 118–24. http://dx.doi.org/10.46660/ojs.v10i3.320.
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Present study deals with petrophysical interpretation of Zaur-03 well for reservoir characterization of sandintervals of Lower Goru Formation in Badin Block, Southern Indus Basin, Pakistan. Early Cretaceous Lower GoruFormation is the distinct reservoir that is producing hydrocarbons for two decades. Complete suite of wireline logsincluding GR log, Caliper log, SP log, Resistivity logs (MSFL, LLS, LLD), Neutron log and Density log along withwell tops and complete drilling parameters were analyzed in this study. The prime objective of this study was to markzones of interest that could act as reservoir and to evaluate reservoir properties including shale volume (Vsh), porosity(ϕ), water saturation (Sw), hydrocarbon saturation (Sh) and net pay thickness. Based on Petrophysical evaluation threezones have been marked in Lower Goru Formation, A Sand (1890m to 1930m), B-sand (1935m to 2010) and C-sand(2015m to 2100m). The average calculated parameters for evaluation of reservoir properties of Zaur-03 well depicts anaverage porosity of 8.92% and effective porosity of 4.81%. Water Saturation is calculated as 28.54% and HydrocarbonsSaturation is 71.46%. Analysis shows that Sh in Zaur-03 well is high so the production of hydrocarbons iseconomically feasible.
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Purba, Leo Rivandi, and Bagus Sapto Mulyatno. "ESTIMASI KANDUNGAN SERPIH (Vsh), POROSITAS EFEKTIF (∅e) DAN SATURASI AIR (Sw) UNTUK MENGHITUNG CADANGAN HIDROKARBON PADA RESERVOAR LIMESTONE LAPANGAN “PRB” DI SUMATERA SELATAN MENGGUNAKAN DATA LOG DAN PETROFISIKA." Jurnal Geofisika Eksplorasi 4, no. 3 (January 17, 2020): 90–102. http://dx.doi.org/10.23960/jge.v4i3.43.
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Log and petrophysics data of research area are that located in South Sumatera Basin, exactly at formation Baturaja will be used for counting the hydrocarbon stock in research field. There are 3 the well datas prosessed to determine the prospect layer of hydrocarbon and estimate the hydrocarbon stock in the productive zone by using 1 petrophysic data from well PRB-3. In order to determine the productive zone of hydrocarbon, the first thing to do is to determine the petrophysics parameters. Parameters used is shale content, effective porosity and water saturation. The value of shale content on “PRB” field shows that reservoir is clean from shale minerals. But, based on the saturation of water, type hydrocarbon in reservoir it is natural gas. Based value of three parameters last, the field “PRB” having 6 zone productive hydrocarbon in each ecploratory wells. Then, determine zone net pay that had been determined by using the cut-off of shale content which is 8% it means hydrocarbon will be produced if the value of shale content under 8%, effective porosity is 5% it means hydrocarbon will be produced if the value of porosity of effective larger than 5% and water saturation is 70% it means that the value of water saturation on field “PRB” must be less than 70% that hydrocarbon can be produced. Average thickness of the net pay in well PRB-1 is 6.78 meter. In well PRB-2, the average thickness is 7.37 meter while in well PRB-3 it is 3,825 meter. The average thickness from those three wells is 3,005 meter. The mean effective porosity of those 3 wells is 8,1% and the mean water saturation is 27,2%. Gas volume formation factor (Bg) is 0,0226 bbl/SCF which the area width is 28 km2. Natural gas stock (OGIP) in this research area is 7,764 BSCF.
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Yin, Chuan, and Terry Thibodeaux. "Analytic formulation for subsurface volumetric estimation." Interpretation 8, no. 2 (May 1, 2020): T465—T473. http://dx.doi.org/10.1190/int-2019-0113.1.
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We have developed an analytic formulation for quick and more accurate volumetric estimations of subsurface resource potential. Our formulation is conceptually based on a structurally conformable model built deterministically using known and interpreted reservoir properties from wells, such as net-to-gross, porosity, and hydrocarbon saturation, along with oil-water contact or lowest known oil depth and interpreted seismic top-of-pay depth horizon. We have evaluated an important function, the hydrocarbon pore capacity (HPC), which is a product of net-to-gross, porosity, and hydrocarbon saturation. HPC reflects the heterogeneity of key reservoir rock and fluid properties, particularly in the vertical direction. We calculated the total hydrocarbon pore volume directly from HPC and the top-of-pay horizon, without the explicit need for building a geologic model first. Our efficient solution form can preserve the vertical resolution of wireline logging with transparent parameterization and the least amount of averaging and upscaling. We also provided additional formulation for incorporating different HPC regimes for cases of multiple existing wells in the reservoir. We demonstrate the practical application of the formulation with a data example from a Cretaceous carbonate reservoir in the southern Gulf of Mexico offshore and with comparisons to other common approaches. In the application example, we determine that the most common approach of using single-average-values can underestimate the reserve upside by as much as 30%, whereas the stochastic modeling approach provided improved estimates when simulating porosity with a lognormal distribution and preserving the net-to-gross log in its original vertical resolution.
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Chen, Bo, Dhananjay Kumar, Anthony Uerling, Sheryl Land, Omar Aguirre, Tao Jiang, and Setiawardono Sugianto. "Using seismic inversion and net pay to calibrate Eagle Ford Shale producible resources." Interpretation 3, no. 3 (August 1, 2015): SV69—SV78. http://dx.doi.org/10.1190/int-2014-0247.1.
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We found a strong correlation between the estimated production volume and hydrocarbon resources in thicker and more porous intervals in the Eagle Ford Shale through integrated petrophysical and engineering analysis. The wells analyzed were selected with similar operational designs so that the rock properties were the main variables impacting the production volume. Seismic data were used to characterize such desired rock properties, including thickness and porosity, to evaluate the producing potentials across the field. Seismic interpretation provided the top and base of the Eagle Ford reservoir, and hence, its thickness. Seismic inversion calibrated the acoustic impedance. Also, the seismic net pay estimation method predicted the thickness of the more porous intervals. The calculated seismic net pay agreed with the well log data. As petrophysical analysis suggested, the seismic net pay also formed a strong correlation with the production volume and has been used to predict the producible resources for new wells, identify refract candidates, and evaluate completion trial methods in the Eagle Ford Shale.
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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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Hampson, Mathew, Heather Martin, Lucy Craddock, Thomas Wood, and Ellie Rylands. "The Elswick Field, Bowland Basin, UK Onshore." Geological Society, London, Memoirs 52, no. 1 (2020): 62–73. http://dx.doi.org/10.1144/m52-2017-29.
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AbstractThe Elswick Field is located within Exploration Licence EXL 269a (Cuadrilla Resources Ltd is the operator) on the Fylde peninsula, West Lancashire, UK. It is the first producing onshore gas field to be developed by hydraulic fracture stimulation in the region. Production from the single well field started in 1996 and has produced over 0.5 bcf for onsite electricity generation. Geologically, the field lies within a Tertiary domal structure within the Elswick Graben, Bowland Basin. The reservoir is the Permian Collyhurst Sandstone Formation: tight, low-porosity fluvial desert sandstones, alluvial fan conglomerates and argillaceous sandstones. The reservoir quality is primarily controlled by depositional processes further reduced by diagenesis. Depth to the reservoir is 3331 ft TVDSS with the gas–water contact at 3400 ft TVDSS and with a net pay thickness of 38 ft.
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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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Gao, Ying, Wei Yao Zhu, Ming Yue, Ai Shan Li, and Shou Ma. "The Non-Darcy Flow Mathematic Model with Fluid-Solid Coupled of Fractured Vertical Well Pattern in Thin Inter-Bedded Reservoirs." Applied Mechanics and Materials 675-677 (October 2014): 1535–40. http://dx.doi.org/10.4028/www.scientific.net/amm.675-677.1535.
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Thin inter-bedded low permeability reservoir is sand layer alternating with mud layer and seriously longitudinal heterogeneous. Fluid flowing in this reservoir presents non-linear seepage characteristics. The dynamic models of porosity and permeability were deduced by the concept of bulk strain. Based on flow field partition principle, oil flow field of overall fractured cross-row well pattern could be divided into four units. Each unit could be divided into three regions with different flow mechanisms. Considering non-Darcy flow and fluid-solid coupled, a mathematical model was established for overall-fractured well pattern in thin inter-bedded reservoirs. The results show that production of well pattern with fluid-solid coupled effect is less than that without. Production of thin inter-bedded reservoir grows with the increase of the ratio of net pay thickness to gross thickness (NTG). With increasing semi-length of hydraulic fracture, production of overall fractured well pattern increases with decreasing increment. The more starting pressure gradient, the smaller production of well pattern in thin inter-bedded low permeability. When the starting pressure gradient exceeds 0.01MPa/m, it influences the production remarkably.
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Hao, Weijun, Zhihong Kang, and Dehua Wu. "Determination of Gas Well Productivity by Logging Parameters." Earth Science Research 6, no. 2 (April 25, 2017): 56. http://dx.doi.org/10.5539/esr.v6n2p56.
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The prediction and evaluation of reservoir productivity is a comprehensive index of the dynamic characteristics of gas reservoirs, which can provide a reasonable basis for the design and rational distribution of gasfield development plan. Proration of gas well is an important procedure in the development process, Absolute open flow as a key indicator of rational production of gas well. It is very important to determine the absolute open flow of the gas well. The Permian in Ordos Basin is a typical tight sandstone gas reservoir. The paper analyses correlation relations between different logging parameters and absolute open flow, and get the four parameters, porosity, permeability, storage coefficient（the product of porosity and effective thickness）with better correlation relations and effective thickness with best correlation relation by combining a large amount of gas logging data and static logging data and means of linear regression analysis, Then on the basis of this, a new empirical formula for calculating the absolute open flow of gas wells is obtained by using the method of multiple linear regression. The example shows that the result of this method is reasonable and reliable and the method can provide scientific basis for the prediction of natural gas absolute open flow of tight sandstone gas reservoirs.
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Alvarez, Pedro, William Marin, Juan Berrizbeitia, Paola Newton, Michael Barrett, and Harry Wood. "Seismic reservoir characterization of a class-1 amplitude variation with offset turbiditic system located offshore Cote d’Ivoire, West Africa." Interpretation 6, no. 2 (May 1, 2018): SD115—SD128. http://dx.doi.org/10.1190/int-2017-0163.1.
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We have evaluated a case study, in which a class-1 amplitude variation with offset (AVO) turbiditic system located offshore Cote d’Ivoire, West Africa, is characterized in terms of rock properties (lithology, porosity, and fluid content) and stratigraphic elements using well-log and prestack seismic data. The methodology applied involves (1) the conditioning and modeling of well-log data to several plausible geologic scenarios at the prospect location, (2) the conditioning and inversion of prestack seismic data for P- and S-wave impedance estimation, and (3) the quantitative estimation of rock property volumes and their geologic interpretation. The approaches used for the quantitative interpretation of these rock properties were the multiattribute rotation scheme for lithology and porosity characterization and a Bayesian lithofluid facies classification (statistical rock physics) for a probabilistic evaluation of fluid content. The result indicates how the application and integration of these different AVO- and rock-physics-based reservoir characterization workflows help us to understand key geologic stratigraphic elements of the architecture of the turbidite system and its static petrophysical characteristics (e.g., lithology, porosity, and net sand thickness). Furthermore, we found out how to quantify and interpret the risk related to the probability of finding hydrocarbon in a class-1 AVO setting using seismically derived elastic attributes, which are characterized by having a small level of sensitivity to changes in fluid saturation.
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Shnawa, Abdulameer T. "GEOLOGICAL PETROPHYSICAL EVALUATION OF YAMAMA FORMATION SUBBA FIELD." Journal of Petroleum Research and Studies 2, no. 2 (May 5, 2021): 97–135. http://dx.doi.org/10.52716/jprs.v2i2.45.
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The main purpose of this study is to estimate hydrocarbon potentialities of Yamama Formation (Valanginian–Early Hauterivian) by using assessment technique links up between gamma ray spectrometry logs and other conventional open hole logs for determining the petrophysical properties of Yamama units in Subba oil-field and oil water contact as well. The Lower Yamama (YB); is considered the main reservoir unit, aptly composed of shallow high depositional energy levels of oolitic to bioclastic grainstone facies reflecting low clay-content, thus these properties had gave a fruitful chance as for immigrated oil to accumulate in the porous bodies of this reservoir units. The non-improved petrophysical properties of upper Yamama member (YA) due to far-deep depositional conditions reflected by well-developed dense-compact sub-tidal open-shelf lagoonal benthic foram / algal wackestone facies and sparse-fossiliferous lime mudstone intercalated with bioclastic wackestone facies, are clearly displayed sedimentary intervals of high clay-content that is, the reduction potential depositional conditions are highly affected on these facies.YB-unit have attained (22-29m) net pay thickness with porosity (9.35-10.9%) and water saturation ranged (40-40.6%),whereas the YA-unit net-pay thickness is reached to (7.5-16.5 m) with (6 % phi) and (35.3%Sw). The oil water contact at the lower Yamama member may assign at depth 3573m (MSL) of southern dome on basis of electrical logs monitoring, well log interpretation and test results carried out the formation units.
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Feyzullayev, A. A., and A. G. Gojayev. "Influence of geological reservoir heterogeneity on exploitation conditions of Garadagh field / underground gas storage (Azerbaijan)." Gornye nauki i tekhnologii = Mining Science and Technology (Russia) 6, no. 2 (July 14, 2021): 105–13. http://dx.doi.org/10.17073/2500-0632-2021-2-105-113.
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Underground oil and gas reservoirs (formations) are characterized by spatial variability of their structure, material composition and petrophysical properties of its constituent rocks: particle size distribution, porosity, permeability, structure and texture of the pore space, carbonate content, electrical resistivity, oil and water saturation and other properties. When assessing development and exploitation conditions for underground gas storages, created in depleted underground oil and gas reservoirs, the inherited nature of the reservoir development should be taken into account. Therefore, identifying the features of variations in well productivity is a crucial task, solution of which can contribute to the creation of more efficient system for underground gas storage exploitation. The paper presents the findings of comparative analysis of spatial variations in well productivity during the exploitation of the Garadagh underground gas storage (Azerbaijan), created in the depleted gas condensate reservoir. An uneven nature of the variations in well productivity was established, which was connected with the reservoir heterogeneity (variations in the reservoir lithological composition and poroperm properties). The research was based on the analysis of spatial variations of a number of reservoir parameters: the reservoir net thickness, lithological composition and poroperm properties. The analysis of variations in the net thickness and poroperm properties of the VII horizon of the Garadagh gas condensate field was carried out based on the data of geophysical logging of about 40 wells and studying more than 90 core samples. The data on of more than 90 wells formed the basis for the spacial productivity variation analysis. The analysis of productivity variation in the space of well technological characteristics (based on data from 18 wells) in the Garadagh underground gas storage (UGS) was carried out through the example of the volume of cyclic gas injection and withdrawal in 2020–2021 season. The studies allowed revealing non-uniform spacial variations in the volumes of injected and withdrawn gas at the Garadagh UGS, created in the corresponding depleted gas condensate reservoir. The features of the UGS exploitation conditions are in good agreement with the features of the reservoir development conditions (variations in the well productivity). The inherited nature of the reservoir development and the underground gas storage exploitation is substantiated by the reservoir heterogeneity caused by the spatial variability of the reservoir lithological composition and poroperm properties. Assessing and taking into account the reservoir heterogeneity when designing underground gas storage exploitation conditions should be an important prerequisite for increasing UGS exploitation efficiency.
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Тихомирова, Елизавета Алексеевна, and Кирилл Павлович Мищенко. "UNCERTAINTY ASSESSMENT FOR HYDROCARBON RESERVES VOLUMETRIC CALCULATION." Вестник Тверского государственного университета. Серия: География и геоэкология, no. 1(33) (March 23, 2021): 35–47. http://dx.doi.org/10.26456/2226-7719-2021-1-35-47.
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В современных экономических условиях остро необходима тщательная проработка рисков и неопределенностей различной природы на этапах разведки и разработки месторождений углеводородов. Особенно важны неопределенности параметров, используемых при подсчете запасов. К ним относятся пористость, эффективная толщина пласта, нефтенасыщенность, объемный коэффициент. В статье рассмотрены существующие подходы к оценке неопределенности параметров, входящих в формулу объемного подсчета запасов, а также предложен способ количественной оценки неопределенности для пористости, песчанистости и нефтенасыщенности с учетом плотности сетки пробуренных скважин. In the current economic conditions, there is an urgent need for a thorough study of risks and uncertainties of various nature at the stages of exploration and development of hydrocarbon deposits. Uncertainties of the parameters used in reserves calculation are especially important. These include porosity, effective reservoir thickness, oil saturation, and volumetric ratio. The article discusses the existing approaches to assessing the uncertainty of the parameters included in the formula for the volumetric calculation of reserves, and also proposes a method for quantifying the uncertainty for porosity, net-gross content and oil saturation, taking into account the density of the grid of drilled wells.
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Ahmad, Naveed, Sikandar Khan, and Abdullatif Al-Shuhail. "Seismic Data Interpretation and Petrophysical Analysis of Kabirwala Area Tola (01) Well, Central Indus Basin, Pakistan." Applied Sciences 11, no. 7 (March 24, 2021): 2911. http://dx.doi.org/10.3390/app11072911.
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Well logging is a significant procedure that assists geophysicists and geologists with making predictions regarding boreholes and efficiently utilizing and optimizing the drilling process. The current study area is positioned in the Punjab Territory of Pakistan, and the geographic coordinates are 30020′10 N and 70043′30 E. The objective of the current research work was to interpret the subsurface structure and reservoir characteristics of the Kabirwala area Tola (01) well, which is located in the Punjab platform, Central Indus Basin, utilizing 2D seismic and well log data. Formation evaluation for hydrocarbon potential using the reservoir properties is performed in this study. For the marked zone of interest, the study also focuses on evaluating the average water saturation, average total porosity, average effective porosity, and net pay thickness. The results of the study show a spotted horizon stone with respect to time and depth as follows: Dunghan formation, 0.9 s and 1080.46 m; Cretaceous Samana Suk formation, 0.96 s and 1174.05 m; Datta formation, 1.08 s and 1400 m; and Warcha formation, 1.24 s and 1810 m. Based on the interpretation of well logs, the purpose of petrophysical analysis was to identify hydrocarbon-bearing zones in the study area. Gamma ray, spontaneous potential, resistivity, neutron, and density log data were utilized. The high zone present in the east–west part of the contour maps may be a possible location of hydrocarbon entrapment, which is further confirmed by the presence of the Tola-01 well.
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Liu, Chuang, Jianhua Zhong, Xi Wang, Mengchun Cao, Jianguang Wu, Shouren Zhang, Xiang Wu, Ningliang Sun, Yan Du, and Yin Liu. "Petrological characteristics and the impact of mineral content on reservoir quality in coal-bearing strata of Linxing area, eastern margin of Ordos Basin, China." Energy Exploration & Exploitation 36, no. 4 (January 24, 2018): 872–94. http://dx.doi.org/10.1177/0144598717753167.
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Tight sandstone gas is on the first position of unconventional natural gas sources, which can be developed under today’s technical conditions. In recent years, tight sandstone gas reservoirs have been found in several wells in the Linxing area, eastern margin of Ordos Basin, China. In this article, a variety of methods, including cast thin sections, X-ray diffraction analysis, scanning electron microscope, and drill core data were used to study the petrological characteristics and their influences on tight sandstone reservoir in coal-bearing strata of the Linxing area. Based on the analysis of thin section, it can be concluded that the sandstone reservoir is essentially constituted of lithic sandstone as well as lithic arkose and feldspathic litharenite. Cement types are complicated, including carbonate minerals, clay minerals, and quartz overgrowth. Illite, kaolinite, chlorite, illite–smectite mixed layer, and chlorite–smectite mixed layer are found in clay minerals. Compared with other clay minerals, illite is in the dominant position. Pores can be divided into residual intergranular pore, intragranular dissolution pore, intergranular dissolution pore, cement dissolution pore, intercrystalline pore, and microcrack in sandstone reservoir of the Linxing area. Quartz has an average content of 68% with the feature of low compositional maturity and plays a major role in increasing porosity due to dissolution and protecting of quartz. Feldspar dissolution plays a role in decreasing porosity because the by-product materials of feldspar dissolution remain in original place, instead of being transported to other areas. Dissolution pores are 2–20 µm and may be filled with kaolinite, illite, or halite. It is worth mentioning that grain-coating chlorite may be of sufficient thickness to protect reservoirs along with the increasing content of chlorite, which is testified by the crossplot between the chlorite and porosity when the absolute content of chlorite is less than 1.5%.
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Mahmoud, Ahmed, Salaheldin Elkatatny, Weiqing Chen, and Abdulazeez Abdulraheem. "Estimation of Oil Recovery Factor for Water Drive Sandy Reservoirs through Applications of Artificial Intelligence." Energies 12, no. 19 (September 25, 2019): 3671. http://dx.doi.org/10.3390/en12193671.
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Hydrocarbon reserve evaluation is the major concern for all oil and gas operating companies. Nowadays, the estimation of oil recovery factor (RF) could be achieved through several techniques. The accuracy of these techniques depends on data availability, which is strongly dependent on the reservoir age. In this study, 10 parameters accessible in the early reservoir life are considered for RF estimation using four artificial intelligence (AI) techniques. These parameters are the net pay (effective reservoir thickness), stock-tank oil initially in place, original reservoir pressure, asset area (reservoir area), porosity, Lorenz coefficient, effective permeability, API gravity, oil viscosity, and initial water saturation. The AI techniques used are the artificial neural networks (ANNs), radial basis neuron networks, adaptive neuro-fuzzy inference system with subtractive clustering, and support vector machines. AI models were trained using data collected from 130 water drive sandstone reservoirs; then, an empirical correlation for RF estimation was developed based on the trained ANN model’s weights and biases. Data collected from another 38 reservoirs were used to test the predictability of the suggested AI models and the ANNs-based correlation; then, performance of the ANNs-based correlation was compared with three of the currently available empirical equations for RF estimation. The developed ANNs-based equation outperformed the available equations in terms of all the measures of error evaluation considered in this study, and also has the highest coefficient of determination of 0.94 compared to only 0.55 obtained from Gulstad correlation, which is one of the most accurate correlations currently available.
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Worthington, Paul F., and Luca Cosentino. "The Role of Cut-offs in Integrated Reservoir Studies." SPE Reservoir Evaluation & Engineering 8, no. 04 (August 1, 2005): 276–90. http://dx.doi.org/10.2118/84387-pa.
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Summary There have been many different approaches to quantifying cutoffs, with no single method emerging as the definitive basis for delineating net pay. Yet each of these approaches yields a different reservoir model, so it is imperative that cutoffs be fit for purpose (i.e., they are compatible with the reservoir mechanism and with a systematic methodology for the evaluation of hydrocarbons in place and the estimation of ultimate hydrocarbon recovery).These different requirements are accommodated by basing the quantification of cutoffs on reservoir-specific criteria that govern the storage and flow of hydrocarbons. In so doing, particular attention is paid to the relationships between the identification of cutoffs and key elements of the contemporary systemic practice of integrated reservoir studies. The outcome is a structured approach to the use of cutoffs in the estimation of ultimate hydrocarbon recovery. The principal benefits of a properly conditioned set of petrophysical cutoffs are a more exact characterization of the reservoir with a better synergy between the static and dynamic reservoir models, so that an energy company can more fully realize the asset value. Introduction In a literal sense, cutoffs are simply limiting values. In the context of integrated reservoir studies, they become limiting values of formation parameters. Their purpose is to eliminate those rock volumes that do not contribute significantly to the reservoir evaluation product. Typically, they have been specified in terms of the physical character of a reservoir. If used properly, cutoffs allow the best possible description and characterization of a reservoir as a basis for simulation. Yet, although physical cutoffs have been used for more than 50 years, there is still no rationalized procedure for identifying and applying them. The situation is compounded by the diverse approaches to reservoir evaluation that have been taken over that period, so that even the role of cutoffs has been unclear. These matters assume an even greater poignancy in contemporary integrated reservoir studies, which are systemic rather than parallel or sequential in nature, so that all components of the evaluation process are interlinked and, therefore, the execution of anyone of these tasks has ramifications for the others (Fig. 1). A particular aspect of the systemic approach is the provision for iteration as the reservoir knowledge-base advances. For example, simulation may be used in development studies to identify the most appropriate reservoir-depletion mechanism, but, once the development plan has been formulated, the dynamic model is retuned and progressively updated as development gets under way. The principal use of cutoffs is to delineate net pay, which can be described broadly as the summation of those depth intervals through which hydrocarbons are (economically) producible. In the context of integrated reservoir studies, net pay has an important role to play both directly and through a net-to-gross pay ratio. Net pay demarcates those intervals around a well that are the focus of the reservoir study. It defines an effective thickness that is pertinent to the identification of hydrocarbon flow units, that identifies target intervals for well completions and stimulation programs, and that is needed to estimate permeability through the analysis of well-test data. The net-to-gross pay ratio is input directly to volumetric computations of hydrocarbons in place and thence to "static" estimates of ultimate hydrocarbon recovery; it is a key indicator of hydrocarbon connectivity, and it contributes to the initializing of a reservoir simulator and thence to "dynamic" estimates of ultimate hydrocarbon recovery.
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Raghavan, R., T. N. Dixon, V. Q. Phan, and S. W. Robinson. "Integration of Geology, Geophysics, and Numerical Simulation in the Interpretation of a Well Test in a Fluvial Reservoir." SPE Reservoir Evaluation & Engineering 4, no. 03 (June 1, 2001): 201–8. http://dx.doi.org/10.2118/72097-pa.
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Summary The focus of this paper is the incorporation of geologic and geophysical data in the analysis of pressure tests in a fluvial reservoir. Using a 3,105,851-cell "porosity cube" derived by seismic and well-log data, this work outlines the steps involved in developing a 3D model with 7,128 cells that was used to estimate reservoir properties (such as permeability, skin, permeability/porosity relationship, reservoir connectivity, and fault factor). The principal steps involved in developing the reservoir model include:identifying all points in the porosity cube that were connected to the wellbore, with porosities above a specified cutoff to identify high-porosity channels and low-porosity overbanks,upscaling the porosity cube to a reasonable size for well-test simulation while preserving pay thickness, pore volume, and connectivity between high- and low-porosity materials; andmatching the observed pressure and pressure-derivative responses with a numerical simulator and a regression program to automatically adjust the reservoir permeability description. A well test in a gas-condensate reservoir is used to demonstrate the ideas outlined in this work. This approach allowed us to identify not only horizontal permeability but also vertical permeability. The issues that need to be considered and the conclusions that are derived on the basis of this work differ significantly from conventional interpretations. Introduction The reservoir considered here is a gas-condensate discovery. Four wells or sidetracks have penetrated the reservoir. In this paper, the test from one of these wells is considered. The purpose of this work is to demonstrate the value of integrating seismic and well-log data into the interpretation of a well test. We believe that this work shows the value using all available data in well-test interpretation. A numerical well-test-simulation model was upscaled from a porosity cube generated by seismic data. Then the well test was matched using automatic history-matching procedures.1 In this paper, we first discuss the development of procedures for generating a 3D well-test model from the porosity cube. Then, we present the process used to obtain a satisfactory history match of the well test. Earlier attempts to match well-test data either by conventional well-test models or by assuming variations in properties derived from amplitude maps were unsatisfactory. The conventional approach suggested that the well produced a two-layer, noncommunicating reservoir, with the high-permeability layer bounded on all sides and the low-permeability layer acting as if it were infinite in extent. This paper is organized into six sections. We begin with a brief review of numerical well-test procedures that are directly pertinent to this work. The second section addresses geological considerations, as this work presumes that a geologic setting is established, and a geological model based on the depositional environment, petrophysics, and seismic interpretations is derived. The end product of the geologic description is a 3D model that quantitatively describes both reservoir properties and reservoir architecture. In the third section, we focus on determining volumes connected to the well and the process of upscaling. Many techniques for upscaling are available and will not be discussed here. In our opinion, for analyzing well behavior, it is important to concentrate on upscaling in the vertical direction. The upscaling procedure we have followed in this study is conceptual and is based on the constraints imposed by the data available to us. The fourth section addresses issues concerning the preparations to be made for the analysis of the specific test under consideration. The preparations are principally governed by operational considerations and the duration of the test. In Sections 2 through 4, we outline our perspective on steps that need to be taken and issues that need to be addressed before pressure data may be analyzed by the outlined scheme. The fifth section analyzes the pressure response both qualitatively and quantitatively. The focus is on reservoir description. Three specific models are considered (all equally reliable). In this section, we show how the production of a well supplements the geologic description. We conclude the paper by noting observations based on this experience. That reservoir description may change as a result of additional measurements is recognized. We should also note, parenthetically, that the sequence of this paper essentially follows the methodology we have used in evaluating pressure tests described in this work. In general, the work-flow process will be governed by the information available to analyze the tests and the objectives of the analysis. Numerical Well-Test Review The numerical simulation of well tests has been conducted for several years.2–4 These early papers were concerned more with numerical than with geological considerations. But in recent years, there has been an increase in the use of numerical simulators to incorporate seismic and geological data into the interpretation of well tests. In general, this work falls into three types: the use of the numerical model to predict the geological model's effect upon the well-test response; the conditioning of geostatistically generated geologic models to the well-test response; and the history matching of the numerical model to observed well-test data. Massonnat and Bandiziol5 review the interdependence between geology and well-test interpretation. Several field examples of how the geology affects well tests or how the well test is used to confirm a geological model are presented. Holden et al.6 used a numerical model of a channel sand to interpret well tests and condition several geostatistical descriptions. Zheng et al.7 used a numerical model to simulate the pressure-test response of wells in meandering channels. The effects of well location within the channel, channel shape, and completion ratios were studied. Corbett et al.8 used a numerical model of braided fluvial reservoirs to calculate well-test responses. A geoskin concept was developed from these data, to be used in a full-field model. Savioli et al.9 used a 1D radial model and regression to analyze well tests. Core permeability/porosity data were used to reduce the number of regression parameters. Matthai et al.10 numerically simulated well-test signatures caused by geologically realistic faults in a sandstone reservoir.
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Yamamoto, Kazuhiro, and Yusuke Toda. "Numerical Simulation on Flow Dynamics and Pressure Variation in Porous Ceramic Filter." Computation 6, no. 4 (September 20, 2018): 52. http://dx.doi.org/10.3390/computation6040052.
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Using five samples with different porous materials of Al2TiO5, SiC, and cordierite, we numerically realized the fluid dynamics in a diesel filter (diesel particulate filter, DPF). These inner structures were obtained by X-ray CT scanning to reproduce the flow field in the real product. The porosity as well as pore size was selected systematically. Inside the DPF, the complex flow pattern appears. The maximum filtration velocity is over ten times larger than the velocity at the inlet. When the flow forcibly needs to go through the consecutive small pores along the filter’s porous walls, the resultant pressure drop becomes large. The flow path length ratio to the filter wall thickness is almost the same for all samples, and its value is only 1.2. Then, the filter backpressure closely depends on the flow pattern inside the filter, which is due to the local substrate structure. In the modified filter substrate, by enlarging the pore and reducing the resistance for the net flow, the pressure drop is largely suppressed.
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Birch, Philip, and Jamie Haynes. "The Pierce Field, Blocks 23/22a, 23/27, UK North Sea." Geological Society, London, Memoirs 20, no. 1 (2003): 647–59. http://dx.doi.org/10.1144/gsl.mem.2003.020.01.51.
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AbstractThe Pierce Field contains oil and gas in Palaeocene Forties Sand and fractured Chalk, draped around the flanks of a pair of Central Graben salt diapirs. Whilst the two diapirs constitute a single field containing over 387 MMSTB AND 125 BCF, it took almost 25 years, and several advances in seismic, drilling and production technology, for the field to be brought into production. Many appraisal wells were drilled on the field. Data from these wells were interpreted to suggest the field was highly segmented both in terms of petroleum distribution and pressure variance. On the basis of this interpretation an economic development required a floating production system with long reach horizontal wells to penetrate the many reservoir segments. The results of development drilling have indicated that few pressure seals exist within the field, with concentric faults being more likely to seal than radial faults. The various reservoir pressures and oil-water contacts have been re-interpreted as a single, highly tilted oil-water contact, facilitated by the location of the field in the low permeability toe of the Forties submarine fan, a major conduit for the transport of basinal fluids away from the deep Central GrabenPalaeocene reservoir depositional patterns closely resemble those predicted by analogue models. The greatest reservoir thickness and net/gross are located in areas of flow velocity reduction (depletive flow), on the 'lee' side of the diapirs, but porosity and permeability are optimized in areas of increased flow velocity (accumulative flow), towards the crests of the diapirsStrontium residual salt analysis has been used to study the charge history of the field. Interpretation suggests that South Pierce was filled before North Pierce, from a local Upper Jurassic source kitchen. Oil and gas subsequently spilled into North Pierce to form a composite trap with a single, tilted oil-water contact. The South Pierce gas cap has since been breached, and the escape of gas is currently leading to the retreat of the tilted water contact, once again isolating the two diapir structures
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Hardage, B. A., J. L. Simmons, V. M. Pendleton, B. A. Stubbs, and B. J. Uszynski. "3-D seismic imaging and interpretation of Brushy Canyon slope and basin thin‐bed reservoirs, northwest Delaware Basin." GEOPHYSICS 63, no. 5 (September 1998): 1507–19. http://dx.doi.org/10.1190/1.1444447.
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A study was done at Nash Draw field, Eddy County, New Mexico, to demonstrate how engineering, drilling, geologic, geophysical, and petrophysical technologies should be integrated to improve oil recovery from Brushy Canyon reservoirs at depths of approximately 6600 ft (2000 m) on the northwest slope of the Delaware basin. These thin‐bed reservoirs were deposited in a slope‐basin environment by a mechanism debated by researchers, a common model being turbidite deposition. In this paper, we describe how state‐of‐the‐art 3-D seismic data were acquired, interpreted, integrated with other reservoir data, and then used to improve the sitting of in‐field wells and to provide facies parameters for reservoir simulation across this complex depositional system. The 3-D seismic field program was an onshore subsalt imaging effort because the Ochoan Rustler/Salado, a high‐velocity salt/anhydrite section, extended from the surface to a depth of approximately 3000 ft (900 m) across the entire study area. The primary imaging targets were heterogenous siltstone and fine‐grained sandstone successions approximately 100 ft (30 m) thick and comprised of complex assemblages of thin lobe‐like deposits having individual thickness of 3 to 6 ft (1 to 2 m). The seismic acquisition was complicated further by (1) the presence of active potash mines around and beneath the 3-D grid that were being worked at depths of 500 to 600 ft (150 to 180 m), (2) shallow salt lakes, and (3) numerous archeological sites. We show that by careful presurvey wave testing and attention to detail during data processing, thin‐bed reservoirs in this portion of the Delaware basin can be imaged with a signal bandwidth of 10 to 100 Hz and that siltstone/sandstone successions 100 ft (30 m) thick in the basal Brushy Canyon interval can be individually detected and interpreted. Further, we show that amplitude attributes extracted from these 3-D data are valuable indicators of the amount of net pay and porosity‐feet in the major reservoir successions and of the variations in the fluid transmissivity observed in production wells across the field. Relationships between seismic reflection amplitude and reservoir properties determined at the initial calibration wells have been used to site and drill two production wells. The first well found excellent reservoir conditions; the second well was slightly mispositioned relative to the targeted reflection‐amplitude trend and penetrated reservoir facies typical of that at other producing wells. Relationships between seismic reflection amplitude and critical petrophysical properties of the thin‐bed reservoirs have also allowed a seismic‐driven simulation of reservoir performance to be initiated.
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Chen, Tielong, Zhengyu Song, Y. Fan, Changzhong Hu, Ling Qiu, and Jinxing Tang. "A Pilot Test of Polymer Flooding in an Elevated-Temperature Reservoir." SPE Reservoir Evaluation & Engineering 1, no. 01 (February 1, 1998): 24–29. http://dx.doi.org/10.2118/36708-pa.
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Summary We conducted a pilot test of polymer flooding in the Shuanghe reservoir located in the southeast Henan oil field, China. The target reservoir has a net thickness of 15.56 m (50 ft), an average permeability of 420 md, and a temperature of 75°C (167°F). The polymers used are two types of modified partially hydrolyzed polyacrylamides, named S525 and S625, which have molecular weights of 16,700,000 and 19,670,000 daltons, respectively. The objective of this pilot test is to investigate the feasibility of polymer flooding for improving oil recovery in an elevated-temperature reservoir. The polymer flooding started in February 1994. Through December 1995, a total of 246 tons (about 0.5×106 lbm) of dry polymer had been used with an injection concentration of 900 to 1,100 ppm. The pore volume (PV) injected reached 0.2164. As a result, oil production increased by 22,000 tons (184,000 bbl) and water production decreased by 153,000 tons (962,000 bbl), which accounts for the incremental oil recovery of 3.8% and water-cut reduction of 5.6% in the test block. We estimate that, by the end of this project, the ultimate increase in oil production will exceed 63,000 tons (528,000 bbl) with the enhanced oil recovery going up to 9.8%. The yield is 0.2 tons more oil produced per kilogram of polymer injected or 0.7 barrel of oil produced per pound of polymer. We attribute the success of the pilot test to the techniques used during the implementation of the flooding, including prevention of polymer-thermal degradation, good reservoir description, and the profile modification carried out before and after the polymer injection. This pilot test illustrates a case where polymers with extra-high molecular weight are successfully injected in an elevated-temperature reservoir to control the mobility ratio and modify the permeability profile. Introduction In recent years, polymer flooding along with other enhanced oil recovery (EOR) projects has been downsized, even suspended, in many research organizations and oil and gas companies because of low oil prices and high operation costs. However, polymer-flooding technology in China has gained prominence for mobility-ratio control and permeability-profile modification. There, laboratory experiments, computer simulation, treatment design, and performance prediction concerning polymer flooding are active research subjects. The need to use polymer flooding in China is caused by the severe heterogeneity of reservoirs, especially in vertical profiles, and the high oil/water viscosity ratio often present. These reservoirs generally are continental formations with complex geological structures, a large variation in reservoir types, and great differences in the fluid properties. To stabilize oil and gas production and to improve oil recovery in the developed fields, China Natl. Petroleum Corp. (CNPC) has adopted policies to encourage and support various EOR projects, including chemical, miscible, thermal, and microbial technology.1 In the past 5 years, several large polymer-flooding projects have been successfully conducted in the Daqing, Dagang, Shengli, Liaohe, and Jilin oil fields.2 Most of the current polymer projects are intended for low-temperature reservoirs. There are very few studies reported on polymer applications in the elevated-temperature reservoirs because polymers generally tend to lose their effectiveness and become unstable under high-temperature conditions. Unfortunately, high-temperature, high-heterogeneity, and high oil/water viscosity ratio are very common in many reservoirs of east China, which is estimated to have a reserve of more than 1.7 billion tons of oil. The previous study showed the promising potential of polymer flooding to improve oil recovery from these reservoirs, if the polymers injected have sufficient thermal stability. To test the feasibility of polymer flooding in elevated-temperature reservoirs, we conducted a pilot test in the Shuanghe reservoir, which has a temperature of 75°C. This paper reports the laboratory studies, reservoir simulation, flooding monitoring, and results of the pilot test. Reservoir Description and Production History Shuanghe Reservoir. Discovered in 1976, the Shuanghe reservoir is located in central China in the southeast Henan oil field, a sizeable field containing 4.557 million tons original oil in place (OOIP). The major producing formation, found at a depth of 1480 m in Tertiary, is a complex sand body made of stacked deltaic cycles (multilayer reservoir). The reservoir is connected with an active aquifer in the east, surrounded by a sealed fault in the south, and smeared out in the northwest. The pilot-test area is located in the southwest area of the reservoir. Fig. 1 shows the well pattern for the pilot test. The lithology of the reservoir formation is described as a sandstone, including 51.8% quartz, 24.8% feldspar, and 23.4% detritus containing 7.5% clay. The clay mineral consists of 44.5% kaolinite, 32.4% illite, 16.8% montmorillonite, and 6.3% chlorite. The reservoir is composed of four layers, known as, and, with permeabilities of 350, 510, 500, and 18 md, respectively. The reservoir formation has an average porosity of 0.216 and average permeability of 420 md, with a variation factor ranging from 0.73 to 0.79. The net thickness of the oil-bearing formation is 15.56 m, and the temperature is 75°C. The crude oil has a viscosity of 7.8 cp at reservoir conditions. Formation water contains 5,060 ppm total dissolved solids (TDS), including 23 ppm of Ca++ and Mg++ combined. The TDS in injection water is 12,000 ppm. Production Histories. The Shuanghe reservoir was put into production in early 1977 and began to be waterflooded in late 1978. To improve the productivity, reduce the water cut, and improve the ultimate oil recovery, infill drilling was done between 1988 and 1992. Before polymer flooding, 23 production wells and 18 injection wells were drilled in the reservoir with a well density of 13.7 wells per km2. The pilot test area is located in the southwest area of the reservoir and contains 19 wells, including seven injection wells and 12 production wells. By February 1994, 33% of oil in place (OIP) had been recovered. The cumulative oil production had reached 0.85 million tons with a water cut more than 92.6%. It is believed that the high water cut can be attributed to the unfavorable water/oil viscosity ratio (1/8) and the severe heterogeneity in vertical and areal directions in the reservoir (permeability variation factor is 0.73 to 0.79). In early 1990, the screening work for EOR methods showed that the use of polymer to thicken water to be injected and to reduce water-phase permeability would improve the mobility ratio dramatically and increase the oil recovery significantly. From 1990 to 1994, extensive laboratory investigations and numerical simulations studied the feasibility of polymer flooding in Shuanghe reservoir. Shuanghe Reservoir. Discovered in 1976, the Shuanghe reservoir is located in central China in the southeast Henan oil field, a sizeable field containing 4.557 million tons original oil in place (OOIP). The major producing formation, found at a depth of 1480 m in Tertiary, is a complex sand body made of stacked deltaic cycles (multilayer reservoir). The reservoir is connected with an active aquifer in the east, surrounded by a sealed fault in the south, and smeared out in the northwest. The pilot-test area is located in the southwest area of the reservoir. Fig. 1 shows the well pattern for the pilot test. The lithology of the reservoir formation is described as a sandstone, including 51.8% quartz, 24.8% feldspar, and 23.4% detritus containing 7.5% clay. The clay mineral consists of 44.5% kaolinite, 32.4% illite, 16.8% montmorillonite, and 6.3% chlorite. The reservoir is composed of four layers, known as, and, with permeabilities of 350, 510, 500, and 18 md, respectively. The reservoir formation has an average porosity of 0.216 and average permeability of 420 md, with a variation factor ranging from 0.73 to 0.79. The net thickness of the oil-bearing formation is 15.56 m, and the temperature is 75°C. The crude oil has a viscosity of 7.8 cp at reservoir conditions. Formation water contains 5,060 ppm total dissolved solids (TDS), including 23 ppm of Ca++ and Mg++ combined. The TDS in injection water is 12,000 ppm. Production Histories. The Shuanghe reservoir was put into production in early 1977 and began to be waterflooded in late 1978. To improve the productivity, reduce the water cut, and improve the ultimate oil recovery, infill drilling was done between 1988 and 1992. Before polymer flooding, 23 production wells and 18 injection wells were drilled in the reservoir with a well density of 13.7 wells per km2. The pilot test area is located in the southwest area of the reservoir and contains 19 wells, including seven injection wells and 12 production wells. By February 1994, 33% of oil in place (OIP) had been recovered. The cumulative oil production had reached 0.85 million tons with a water cut more than 92.6%. It is believed that the high water cut can be attributed to the unfavorable water/oil viscosity ratio (1/8) and the severe heterogeneity in vertical and areal directions in the reservoir (permeability variation factor is 0.73 to 0.79). In early 1990, the screening work for EOR methods showed that the use of polymer to thicken water to be injected and to reduce water-phase permeability would improve the mobility ratio dramatically and increase the oil recovery significantly. From 1990 to 1994, extensive laboratory investigations and numerical simulations studied the feasibility of polymer flooding in Shuanghe reservoir.
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Clarkson, Christopher R., R. Marc Bustin, and John P. Seidle. "Production-Data Analysis of Single-Phase (Gas) Coalbed-Methane Wells." SPE Reservoir Evaluation & Engineering 10, no. 03 (June 1, 2007): 312–31. http://dx.doi.org/10.2118/100313-pa.
Full textAbstract:
Summary Coalbed-methane (CBM) reservoirs commonly exhibit two-phase-flow (gas plus water) characteristics; however, commercial CBM production is possible from single-phase (gas) coal reservoirs, as demonstrated by the recent development of the Horseshoe Canyon coals of western Canada. Commercial single-phase CBM production also occurs in some areas of the low-productivity Fruitland Coal, south-southwest of the high-productivity Fruitland Coal Fairway in the San Juan basin, and in other CBM-producing basins of the continental United States. Production data of single-phase coal reservoirs may be analyzed with techniques commonly applied to conventional reservoirs. Complicating application, however, is the unique nature of CBM reservoirs; coal gas-storage and -transport mechanisms differ substantially from conventional reservoirs. Single-phase CBM reservoirs may also display complex reservoir behavior such as multilayer characteristics, dual-porosity effects, and permeability anisotropy. The current work illustrates how single-well production-data-analysis (PDA) techniques, such as type curve, flowing material balance (FMB), and pressure-transient (PT) analysis, may be altered to analyze single-phase CBM wells. Examples of how reservoir inputs to the PDA techniques and subsequent calculations are modified to account for CBM-reservoir behavior are given. This paper demonstrates, by simulated and field examples, that reasonable reservoir and stimulation estimates can be obtained from PDA of CBM reservoirs only if appropriate reservoir inputs (i.e., desorption compressibility, fracture porosity) are used in the analysis. As the field examples demonstrate, type-curve, FMB, and PT analysis methods for PDA are not used in isolation for reservoir-property estimation, but rather as a starting point for single-well and multiwell reservoir simulation, which is then used to history match and forecast CBM-well production (e.g., for reserves assignment). CBM reservoirs have the potential for permeability anisotropy because of their naturally fractured nature, which may complicate PDA. To study the effects of permeability anisotropy upon production, a 2D, single-phase, numerical CBM-reservoir simulator was constructed to simulate single-well production assuming various permeability-anisotropy ratios. Only large permeability ratios (>16:1) appear to have a significant effect upon single-well production characteristics. Multilayer reservoir characteristics may also be observed with CBM reservoirs because of vertical heterogeneity, or in cases where the coals are commingled with conventional (sandstone) reservoirs. In these cases, the type-curve, FMB, and PT analysis techniques are difficult to apply with confidence. Methods and tools for analyzing multilayer CBM (plus sand) reservoirs are presented. Using simulated and field examples, it is demonstrated that unique reservoir properties may be assigned to individual layers from commingled (multilayer) production in the simple two-layer case. Introduction Commercial single-phase (gas) CBM production has been demonstrated recently in the Horseshoe Canyon coals of western Canada (Bastian et al. 2005) and previously in various basins in the US; there is currently a need for advanced PDA techniques to assist with evaluation of these reservoirs. Over the past several decades, significant advances have been made in PDA of conventional oil and gas reservoirs [select references include Fetkovich (1980), Fetkovich et al. (1987), Carter (1985), Fraim and Wattenbarger (1987), Blasingame et al. (1989, 1991), Palacio and Blasingame (1993), Fetkovich et al. (1996), Agarwal et al. (1999), and Mattar and Anderson (2003)]. These modern methods have greatly enhanced the engineers' ability to obtain quantitative information about reservoir properties and stimulation/damage from data that are gathered routinely during the producing life of a well, such as production data and, in some instances, flowing pressure information. The information that may be obtained from detailed PDA includes oil or gas in place (GIP), permeability-thickness product (kh), and skin (s), and this can be used to supplement information obtained from other sources such as PT analysis, material balance, and reservoir simulation.
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Tye, Robert S., Donald R. Lowe, and J. J. Hickey. "Ediacaran (Vendian)-period alluvial and coastal geomorphology applied to development of Verkhnechonskoye and Yaraktinskoye fields, East Siberia, Russian Federation." Journal of Sedimentary Research 90, no. 1 (January 22, 2020): 67–101. http://dx.doi.org/10.2110/jsr.2020.8.
Full textAbstract:
ABSTRACT Ediacaran-age (635–542 Ma) oil-bearing strata in the Yarakta Horizon at the Verkhnechonskoye and Yaraktinskoye fields, East Siberia, consist of conglomerate, sandstone, dolomitic sandstone, and mudstone overlying and onlapping igneous to metasedimentary highlands of the East Siberia craton. Initial drainage networks formed within structurally defined valleys, and early deposition occurred in localized alluvial to shallow-marine depositional systems. Base-level-controlled depositional cycles aggraded the valleys; thus, as valleys aggraded, they buried interfluves and coalesced forming broad alluvial and coastal plains. Three to seven bedsets of variable net-to-gross content constitute a genetic cycle. Depositional cycles varied locally, as nine and eight cycles separated by decimeter- to multi-meter-thick mudstones are defined at Verknechonskoye and Yaraktinskoye, respectively. Within one genetic cycle, facies associations grade basinward from alluvial (channel-bar, channel-fill, floodplain, playa, and crevasse-splay) to shallow marine (sabkha, tidal-flat, estuarine-channel, and poorly developed shoreface). Coarse-grained lithofacies are typically arranged in decimeter- to meter-scale bedsets with sharp to scoured bases. Bedsets commonly, but not always, show an upward decrease in grain size, bed thickness, and scale of sedimentary structure. Typically, medium-grained sandstones exhibit low-angle cross bedding and are gradationally overlain by fine-grained sandstones exhibiting scour-and-fill, cuspate-ripple lamination, climbing-ripple lamination, and parallel lamination. Clay clasts and small pebbles are accessories. Interbedded mudstones, siltstones, and sandstones show ripple cross bedding, wavy to lenticular bedding, abundant soft-sediment deformation (e.g., shear, fluid-escape, slump features), and slickensides. Thin-bedded sandstones are micaceous and contain granule-size mud chips. Some mudstones exhibit crinkled to parallel laminae indicative of algal growth. Sandstone fills mudcracks. Interbedded green and black mudstones, plus pyrite and siderite cements, indicate alternating redox conditions. Alluvial facies have patchy quartz, anhydrite, and carbonate cements. Marine-influenced facies show early and well-developed quartz cement as well as abundant halite. Gypsum and halite dissolution formed secondary pores. Calculated estimates of fluvial-channel dimensions and sinuosities indicate that despite the lack of vegetation, fluvial channels in the Yarakta Horizon were shallow and relatively narrow, moderately sinuous, and exhibited varying degrees of mud-prone overbank deposition. Recognition and correlation of flooding surfaces and channel diastems bounding genetically related strata identified multiple stratigraphic compartments in each field. Porosity loss at chronostratigraphic boundaries accounts for complex water, oil, and gas contacts. Economic field development is hampered by locally varying reservoir quality and sandstone continuity caused by its channelized and onlapping stratigraphy and diagenesis. Reservoir simulation of varying geostatistical models demonstrate that differing porosity-distribution methods had little effect on estimates of in-place hydrocarbon volumes. Model differences in porosity and permeability distribution and lithofacies connectivity show large variations in recovery factor and productivity/injectivity.
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Buciak, J., G. Fondevila Sancet, and L. Del Pozo. "Polymer-Flooding-Pilot Learning Curve: Five-Plus Years' Experience To Reduce Cost per Incremental Barrel of Oil." SPE Reservoir Evaluation & Engineering 18, no. 01 (November 11, 2014): 11–19. http://dx.doi.org/10.2118/166255-pa.
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Summary This paper deals with the learning curve of a five-plus-year polymer-flooding pilot conducted in a mature waterflood that includes, for example, several works related to injector and producer wells and reservoir management. The scope of this paper is to describe the learning curve during the last 5 years rather than the reservoir response of the polymer-flooding technique; focus is on the aspects related to reduce cost per incremental barrel of oil for a possible extension to other waterflooded areas of the field. Diadema oil field is in the San Jorge Gulf basin in the southern portion of Argentina. The field is operated by CAPSA, an Argentinean oil-producer company; it has 480 producer and 270 injector wells (interwell spacing is 250 m on average). The company has developed waterflooding over more than 18 years (today, this technique represents 82% of oil production in the field) and produces approximately 1600 m3/d of oil and 40 000 m3/d of gross production (96% water cut) with 38 400 m3/d of water injection. The reservoir that is polymer-flooded is characterized by high permeability (average of 500 md), high heterogeneity (10 to 5,000 md), high porosity (30%), very stratified sandstone layers (4 to 12 m of net thickness) with poor lateral continuity (fluvial origin), and 20 °API oil (100 cp at reservoir conditions). Diadema's polymer-flooding pilot started in October 2007 on five water injectors (it includes 13 injectors today) with an injected rate of 1000 m3/d (today, 2000 m3/d). Polymer solution is made with produced water (15,000 ppm brine) and 1,500 ppm of hydrolyzed polyacrylamide polymer reaching 15- to 20-cp fluid-injection viscosity. Oil-production rate from the original “central” producers (wells that are aided with 100% of polymer injection) has increased 100% at the same time as average reduction in water cut is approximately 15%. The main aspects presented in this work are depth profile modification with crosslinked gel injected along with polymer, use of “curlers” to regulate injection in multiple wells with one injection pump without shearing the polymer, and an improved technology on producer wells with progressing-cavity pumps to decrease shut-in time and number of pump failures. The plan for the future is to extend this project to other areas with the acquired knowledge and to improve different aspects, such as water quality and optimization of polymer plant operation. These improvements will allow the company to reduce operating costs per incremental barrel of oil.
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Grieser, William V., Robert F. Shelley, Bill J. Johnson, Eugene O. Fielder, James R. Heinze, and James R. Werline. "Data Analysis of Barnett Shale Completions." SPE Journal 13, no. 03 (September 1, 2008): 366–74. http://dx.doi.org/10.2118/100674-pa.
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Summary The north Texas Barnett shale illustrates the successful commercialization of an unconventional reservoir. However, it took 17 years to evolve from pumping crosslinked gel (XLG) carrying more than 1 million lbm of proppant per job to sand waterfracs (SWFs) consisting of large volumes of water with friction reducer and small quantities of sand. This transition to SWF stimulation opened the door for widespread development that has advanced the Newark East (Barnett shale) to the largest producing gas field in Texas. This paper investigates Barnett completion strategy from 1993 to 2002. The 393-well data set includes completion, reservoir, and production data. Unique data-evaluation tools and techniques were used to investigate various completion and reservoir parameters to determine their effects on production (Shelley and Stephenson 2000; Zangl and Hannerer 2003). We found that production results show a broad scattering when crossplotted with various completion and reservoir inputs. This result is not uncommon when analyzing field data. However, general trends were identified through comparisons of large numbers of wells. These trends were confirmed through the use of more-advanced data-mining techniques, which included self-organizing mapping (SOM) of data. The results show that SWF-type stimulation of the Barnett outperformed to varying degrees XLG treatments for the five reservoir types used in this evaluation. Geology The Barnett is a Mississippian marine shelf deposit. The Barnett shale ranges in thickness from 200 ft in the southwest region to 1,000 ft in the northeast near the Munster arch. The formation is described as a black, organic-rich (total organic content 4.5%) shale composed of fine-grained, nonsiliciclastic rocks with extremely low permeability (0.00007 to 0.005 md). The organic matter in the shale was first reported to contain 60 scf/ton but could be as high as 200 scf/ton (Montgomery et al. 2005). The Barnett is described as a "spent oil-prone source rock with porosity and permeability developed with thermal transformation of its organic matter from liquid to gas with resulting maturation-induced microfractures" (Jarvie et al. 2004). While the Barnett is classified as shale, it is complex and not homogeneous. In the core area (Denton and Wise counties), the Barnett is composed of two producing intervals notated as the upper and lower Barnett. These intervals are separated by the Forestburg lime, which varies in thickness from 20 ft to more than 150 ft. When production from the lower and upper Barnett is commingled, the lower Barnett contribution is 75-80% of the total. This value has been verified from production logs and from measuring production when isolating the intervals and producing them individually. The lower boundary (Viola/Simpson) pinches out west of the core area. The Ellenberger is a known water source, so stimulation of the lower Barnett without the Viola/Simpson can lead to high water production. Another potential for water production is the Viola, which in some areas has high water-production potential. Historical Completion Practices The first stimulation completion of the Barnett used nitrogen gas as the injection fluid. In early Barnett development, a concern about the high clay content in the shale led to precautions when using water-based fluids. An average mineral analysis from samples collected in Wise County, Texas, is given in Table 1. Early completion fluids tended to be foamed or gas-assisted. Our data set begins approximately 4 years before the first SWF was attempted. Reasons for this transition were predominately driven by economics. SWFs provided the operator with a substantial savings in stimulation costs; however, the ability to place high concentrations of proppant was eliminated. SWF began in 1997-98, and the assumption was that the Barnett would respond to a sand concentration of less than a monolayer and yield commercial production (Grieser et al. 2003). The lower Barnett was the only interval completed during the early development of the Barnett field using XLG-type treatments. The upper Barnett interval was added to the completion when the SWF era began. The addition of upper and lower net pay in the wells treated with SWF is the reason for the extra thickness. The cost savings that were realized with the evolution to the SWF enabled the additional expenditure for completing the upper Barnett. Stimulation treatment averages and production outcome are given in Table 2 for XLG fracs and SWF.
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Scheevel, J. R., and K. Payrazyan. "Principal Component Analysis Applied to 3D Seismic Data for Reservoir Property Estimation." SPE Reservoir Evaluation & Engineering 4, no. 01 (February 1, 2001): 64–72. http://dx.doi.org/10.2118/69739-pa.
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Summary We apply a common statistical tool, Principal Component Analysis (PCA) to the problem of direct property estimation from three-dimensional (3D) seismic-amplitude data. We use PCA in a novel way to successfully make detailed effective porosity predictions in channelized sand and shale. The novelty of this use revolves around the sampling method, which consists of a small vertical sampling window applied by sliding along each vertical trace in a cube of seismic-amplitude data. The window captures multiple, vertically adjacent amplitude samples, which are then treated as vectors for purposes of the PCA analysis. All vectors from all sample window locations within the seismic-data volume form the set of input vectors for the PCA algorithm. Final output from the PCA algorithm can be a cube of assigned classes, whose clustering is based on the values of the most significant principal components (PC's). The clusters are used as a categorical variable when predicting reservoir properties away from well control. The novelty in this approach is that PCA analysis is used to analyze covariance relationships between all vector elements (neighboring amplitude values) by using the statistical mass of the large number of vectors sampled in the seismic data set. Our approach results in a powerful signal-analysis method that is statistical in nature. We believe it offers data-driven objectivity and a potential for property extraction not easily achieved in model-driven fourier-based time-series methods of analysis (digital signal processing). We evaluate the effectiveness of our method by applying a cross-validation technique, alternately withholding each of the three wells drilled in the area and computing predicted effective porosity (PHIE) estimates at the withheld location by using the remaining two wells as hard data. This process is repeated three times, each time excluding only one of the wells as a blind control case. In each of the three blind control wells, our method predicts accurate estimates of sand/shale distribution in the well and effective porosity-thickness product values. The method properly predicts a low sand-to-shale ratio at the blind well location, even when the remaining two hard data wells contain only high sand-to-shale ratios. Good predictive results from this study area make us optimistic that the method is valuable for general reservoir property prediction from 3D seismic data, especially in areas of rapid lateral variation of the reservoir. We feel that this method of predicting properties from the 3D seismic is preferable to traditional, solely variogram-based geostatistical estimation methods. Such methods have difficulty capturing the detailed lithology distribution when limited by the hard data control's sampling bias. This problem is especially acute in areas where rapid lateral geological variation is the rule. Our method effectively overcomes this limitation because it provides a deterministic soft template for reservoir-property distributions. Introduction Reservoir Prediction from Seismic. The use of the reflection seismic-attribute data for the prediction of detailed reservoir properties began at least as early as 1969.1 Use of seismic attributes for reservoir prediction has accelerated in recent years, especially with the advent of widely available high-quality 3D seismic data. In practice, a seismic attribute is any property derived from the seismic reflection (amplitude) signal during or after final processing. Any attributes may be compared with a primary reservoir property or lithology in an attempt to devise a method of attribute-guided prediction of the primary property away from well control. The prediction method can vary from something as simple as a linear multiplier (single attribute) to multi-attribute analysis with canonical correlation techniques,2 geostatistical methods,3 or fully nonlinear, fuzzy methods.4 The pace of growth in prediction methodologies using seismic attributes seems to be outpaced only by the proliferation in the number and types of seismic attributes reported in the literature.5 As more researchers find predictive success with one or more new attributes, the list of viable reservoir-predictive attributes continues to grow. Chen and Sidney6 have cataloged more than 60 common seismic attributes along with a description of their apparent significance and use. Despite the rich history of seismic attribute in reservoir prediction, the practice remains difficult and uncertain. The bulk of this uncertainty arises from the unclear nature of the physics connecting many demonstrably useful attributes to a corresponding reservoir property. Because of the complex and varied physical processes responsible for various attributes, the unambiguous use of attributes for direct reservoir prediction will likely remain a challenge for years to come. In addition to the questions about the physical origin of some attributes, there is the possibility of encountering statistical pitfalls while using multiple attributes for empirical reservoir-property prediction. For example, it has been demonstrated that as the number of attributes used in an evaluation increases, the potential arises that one or more attributes will produce a false correlation with well data.7 Also, many attributes are derived with similar signal-processing methods and can, in some cases, be considered largely redundant with respect to their seismic-signal description. Lendzionowski et al.8 maintain that the maximum number of independent attributes required to fully describe a trace segment is a quantity 2BT, where B=bandwidth (Hz) and T=trace-segment length (sec). If this is supportable, it suggests that most of the more common attributes are at least partially redundant. The danger of such redundancy is that it falsely enhances statistical correlation with the well property. Doing so may suggest that many seemingly independent seismic attributes display similar well-property trends. Finally, the use of a particular approach with attributes involves some subjectivity and prior experience on the part of the practitioner to be successful and reproducible. This is a source of potential error that cannot be quantified but also, in most cases, cannot be avoided. The most successful workers in the field of reservoir prediction from seismic, not coincidentally, are also the most experienced in the field.
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Carter, Robert D. "Type Curves for Finite Radial and Linear Gas-Flow Systems: Constant-Terminal-Pressure Case." Society of Petroleum Engineers Journal 25, no. 05 (October 1, 1985): 719–28. http://dx.doi.org/10.2118/12917-pa.
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Carter, Robert D., SPE, Amoco Production Co. Abstract This paper presents gas-production-rate results in type curve form for finite radial and linear flow systems produced at a constant terminal (bottomhole) pressure. These produced at a constant terminal (bottomhole) pressure. These results can be used in the analysis of actual gas and oil rate/time data to estimate reservoir size and to infer reservoir shape. The type curves are based on dimensionless variables that are a generalized form of those presented previously. In addition, an approximate drawdown previously. In addition, an approximate drawdown parameter is presented. Example applications that parameter is presented. Example applications that demonstrate the applicability of the type curves to a variety of reservoir configurations are given. The Appendix contains derivations of the dimensionless variables and the drawdown parameter. Introduction The gas-bearing rock in some low-permeability gas fields consists of sandstone lenses of uncertain but limited size. In such fields, the reservoir area and volume drained by individual wells cannot be inferred from well spacing. Moreover, good reserve estimates using plots of p/z vs. cumulative production are often not possible because of the difficulty of obtaining reservoir pressure from buildup tests. Therefore, reserve estimation techniques that use performance data, such as production rate as a function performance data, such as production rate as a function of time, are needed. Although this problem has been recognized, the techniques proposed in the past for application to gas reservoirs have been mostly empirical. The present work offers a method that is consistent with the basic theory of gas flow in porous media for analyzing production data to estimate reserves. This method will also provide some inference about reservoir shape. Type Curves Basic Assumptions Six basic assumptions are made in generating the type curves.The flow geometry is radial; therefore, the reservoir either is circular and is produced by a concentrically located well of finite radius or is a sector of a circle produced by the corresponding sector of the well (Fig. 1). produced by the corresponding sector of the well (Fig. 1). In the limit as, the flow regime becomes a linear one.Permeability, porosity, and thickness are constant throughout the reservoir.The pressure at the well radius (usually corresponding to the bottomhole flowing pressure CBHFP]) is held constant.The initial reservoir pressure is constant (independent of position).Non-Darcy flow is neglected.The flowing fluid is either a gas with viscosity and compressibility that vary with pressure or an oil with a constant viscosity/compressibility product. Definitions. The type curves are based on specially defined dimensionless time (tD), dimensionless rate (qD), a flow geometry parameter ( ), and a drawdown parameter ( ). These variables are defined by the following parameter ( ). These variables are defined by the following equations, which are derived in the Appendix. ............................ (1) ................................(2) ...............................(3) .....................(4) Results The type curves for rate as a function of time are presented in Fig. 2. A finite-difference radial-gas-flow simulator was used to generate the data for constructing the type curves. Two flow periods can be identified. The infinite-acting (or transient) period is that period before which the curves become concave downward. The transient period ends at to values ranging from about 0.15 to about 1.0, depending on the value of 17 that characterizes the curve. The curves are concave downward during the late-time or depletion period. Notice that the primary characterizing parameter during the infinite-acting period is, and is parameter during the infinite-acting period is, and is the characterizing parameter for late-time behavior (tD >1). The curves for = 1.234 (linear flow) are straight lines with a negative half-slope during the infinite-acting period. SPEJ p. 719
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Sarkar, Amit K., Lee Jaedong, and Ekrem Kasap. "Adverse Effects of Poor Mudcake Quality: A Supercharging and Fluid Sampling Study." SPE Reservoir Evaluation & Engineering 3, no. 03 (June 1, 2000): 256–62. http://dx.doi.org/10.2118/64227-pa.
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Summary Wireline formation testers are routinely used at discrete depths of a well to collect reservoir fluid samples and to estimate undisturbed reservoir pressures, near-wellbore formation permeabilities, fluid compressibilities, and saturation pressures. A pressure profile in the vertical direction yields fluid densities and fluid contacts (gas/oil and water/oil contacts) in the reservoir. Reliable results are obtained when the mudcake isolates the wellbore from the formation. When the mudcake cannot provide isolation, mud filtrate invasion continues and supercharging occurs. The issue of sample quality becomes critical when using oil-based muds because the filtrate is also oil and is difficult to separate from the formation oil, a pure sample of which is needed for fluid characterization studies. This study investigated the effects of poor mudcake seal on sample quality and formation test data and its analysis when oil-based muds are used. Modeling studies were conducted using a finite-element simulator. The results of the study indicate that mudcake permeabilities must be less than 1 µd and mudcake-to-formation permeability ratios must be less than 10–4 to achieve sample qualities higher than 90%. Such conditions as high pumpout rates, low overbalance pressures, and shallow filtrate invasion depths improve sample quality. The presence of a permeability-damaged zone around the mudcake improves the sample quality but reduces the sampling pressure. The formation rate analysis (FRASM)*** technique estimates formation permeability accurately in the presence or absence of supercharging. The formation pressure estimated using the buildup data is the pressure at the mudcake-formation interface. The supercharged pressure must be subtracted from the apparent formation pressure to obtain the true formation pressure. A simple procedure is developed for estimating the mudcake permeability and the supercharged pressure. Supercharged pressure is shown to be a product of the apparent overbalance pressure, mudcake-to-formation permeability ratio, and an invasion factor representing the distance up to which supercharging extends. Introduction Drilling typically alters formations in such a way that a mudcake, a fines-invaded zone, and a filtrate-invaded zone are created between the wellbore and the native formation (Fig. 1, top). Zone properties such as thickness, permeability, porosity, and fluid saturation depend upon the mud and formation properties, hole size, and overbalance pressure, which is the difference between the wellbore and the formation pressure. Mudcake is an external (outside the formation) layer created by the fines-migration mechanisms of size exclusion and bridging.1 The fines-invaded zone is created by smooth deposition and bridging. The fines involved are generated by the processes of drilling, sudden salinity changes in porous media, and high viscous forces. The zone permeability may be an order of magnitude less than that of the formation. The filtrate-invaded zone usually extends beyond the fines-invaded zone. Poor quality mudcakes with low thicknesses and high permeabilities are commonly formed on surfaces of low permeability formations because the rate of filtrate flow through the formation is low. The filtrate invasion continues and the pressures in the near-wellbore area are higher than the native formation pressure. This phenomenon is called supercharging (Fig. 1, bottom). Use of oil-based muds has increased recently because of advantages such as faster penetration, good wellbore stability, better lubrication that is especially important in deviated wellbores, and less solid and filtrate invasion into the formation. Lee and Kasap2 used a three-dimensional, single-phase, two-component, isothermal finite-element simulator to study the quality of samples (fraction of formation oil in the sample) received from a wireline formation tester (WFT) when oil-based muds were used. The simulator models wellbore geometry and formation-tool connections realistically; wellbore radius, mudcake thickness, permeability, and porosity are simulated functionally. Effects of viscous and dispersive forces are considered but not those of gravitational forces. For a sealing-type of mudcake, the results indicated that the sample quality reached 90% for a filtrate invasion distance of 10 cm. The rate of increase in sample quality with further pumpout was too low. The pumpout rate and formation permeability were insensitive parameters. The pumpout time required to obtain high-quality samples increased exponentially with the depth of filtrate invasion. The presence of a permeability-damaged zone around the wellbore improved sample quality because the angular inflow of filtrate from the invaded zone decreased. Higher formation anisotropy (horizontal-to-vertical permeability ratio) also improved sample quality because the vertical flow from the filtrate-invaded zone decreased. Effects of leaking mudcakes have previously been studied to a limited extent.2,3 This study investigates the effects of mudcake quality on fluid sampling and supercharging when oil-based muds are used. The results of the study indicate that both the mudcake permeability and the mudcake-to-formation permeability ratio must be low to achieve high-quality samples. Conditions including high pumpout rates, low overbalance pressures, and shallow filtrate invasion depths improve sample quality. The presence of a permeability-damaged zone around the mudcake improves sample quality but reduces the sampling pressure. A simple procedure is developed for estimating the supercharged pressure that must be subtracted from the apparent reservoir pressure to obtain the true formation pressure.
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Weber, K. J., and Hans Dronkert. "Screening Criteria to Evaluate the Development Potential of Remaining Oil in Mature Fields." SPE Reservoir Evaluation & Engineering 2, no. 05 (October 1, 1999): 405–11. http://dx.doi.org/10.2118/57873-pa.
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Summary Continuing reservoir management at mature stages often concentrates on delineating pockets of remaining mobile oil. This is becoming a major task for reservoir geologists and petrophysicists. Many old fields are coming up for reactivation as investment opportunities and there is an overall expectation that modern techniques can lead to additional recovery of between 10 and 20%. In this article we will discuss the screening criteria related to reservoir architecture, accumulation condition and production history. The mobile oil remaining can be found in a number of predictable locations in reservoirs depending on their structural style and facies. Attic oil along faults is perhaps the most simple configuration but sizeable volumes of remaining oil can also occur as a function of reservoir stratification and lateral discontinuity. A systematic overview of the different play types has been compiled based on structural or stratigraphic lateral continuity and vertical reservoir connectivity. Screening criteria have been derived on the basis of field examples and models for four play types. The screening criteria specify minimum conditions which may lead to economic re-development with horizontal sidetracks from existing wells. In addition recommendations are given with respect to data gathering to confirm the presence of economically viable targets. Introduction Numerous oil fields that have been in production for many years are currently being reviewed to evaluate options for increasing their ultimate recovery. The task involves determination of the volume and location of remaining mobile oil and subsequently the technical and economic assessment of methods to recover this oil. The first part of this task is often difficult because of the poor quality of the data often associated with old fields. Nevertheless, certain basic data are usually available and the purpose of this article is to provide first round screening criteria based on these data in order to select those reservoirs for which re-development schemes are more likely to be economical. For the reservoirs selected, further study and some additional data acquisition will be warranted. The data that may be expected to be present consist of well logs, limited core measurements, basic facies descriptions, original oil-in-place and cumulative production figures, structure maps and well positions. Having access to well completion data is also essential. Individual well performance data are often difficult to obtain. The proposed screening scheme is based on a classification of the types of remaining oil configurations. Once such a potential oil pocket has been recognized, an attempt is made to assess its economic value by estimating a number of parameters with a limited degree of accuracy. Dip, original accumulation conditions, bedding thickness, reservoir profile, porosity distribution and original oil saturation can often be determined satisfactorily. More detailed reservoir architecture and particularly permeability distributions are more difficult to obtain. The classification scheme for mobile remaining oil pockets consists of a division into reservoirs with either high or low vertical permeability/connectivity and a further subdivision into types with a high and low horizontal connectivity. In this article four major types of mobile remaining oil configurations, representing the four combinations of high and low vertical and horizontal conductivity, are discussed. The screening criteria presented are based on re-development with pairs of horizontal sidetracks from existing wells. A cost of $1,000,000 has been assumed per job for re-entering the hole, milling the casing and drilling and completion of the two sidetracks each of 300 m length. This is based on a variety of cost estimates obtained for land operations. The economic analysis based on this method and on the cost level shows a remarkably large scope for re-development of reservoirs with oil rims, attic oil cases in faulted reservoirs and layer cake reservoirs with beds of contrasting permeability. Fluvial labyrinth type reservoirs1 are much more difficult to re-develop but a number of observations are made to suggest more favorable configurations. Classification of Remaining Mobile Oil Configurations The retention of mobile oil in sufficiently large volumes to allow economic re-development is largely controlled by the presence of heterogeneous pressure distribution and the fluid density and viscosity contrasts. This article is restricted to sandstone reservoirs containing light oil that have been developed with vertical wells and produced under reasonable draw-down conditions. In view of the potential for recompletion and infill drilling, the most important heterogeneities are faults, boundaries of genetic units, large permeability contrasts and baffles to flow such as shale intercalations. Following the subdivisions of clastic reservoirs into layer cake, jigsaw puzzle and labyrinth types one can already predict a number of typical oil displacement patterns. By considering major large scale heterogeneities we can subdivide the reservoirs into types with a high vertical conductivity and those in which stratification and low permeable intercalations result in low vertical conductivity. Next we can make a further distinction between layer cake reservoirs with a high degree of lateral continuity of the beds and reservoirs where the lateral continuity is limited by faults or pinchouts of the sand bodies. This leads to the scheme shown in Fig. 1. To the first category, A, we can attribute oil-rim reservoirs with a high vertical conductivity in which unproducible oil columns are left between the vertical wells as a result of cusping and coning. Poor lateral continuity can be formed by a normal fault (B1) which, even when nonsealing over the juxtaposed reservoir interval, traps oil in the up-thrown block against the caprock in the down-thrown block. Depending on the throw of the fault, the structural dip and the distance of the vertical wells from the fault, a volume of oil will remain when the well water runs out. In labyrinth reservoirs one finds updip stratigraphic traps (B2) especially in low net/gross (N/G) cases. In such cases we also encounter poor sweep efficiency unless the well spacing is small (D). Poor sweep can also result from stratification with large permeability contrast between the beds, particularly when these are separated by impermeable intercalations (C). This situation is quite common in layer cake reservoirs. Even without impermeable separations crossflow may be limited if the vertical permeability of the low permeability layer is low. This situation frequently occurs in fluvial labyrinth reservoirs and this can occur in combination with configurations B1 and D.
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Cooper, Gareth, Roger Xiang, Nick Agnew, Phil Ward, Mark Fabian, and Neil Tupper. "A systematic approach to unconventional play analysis: the oil and gas potential of the Kockatea Shale and Carynginia Formation, North Perth Basin, Western Australia." APPEA Journal 55, no. 1 (2015): 193. http://dx.doi.org/10.1071/aj14015.
Full textAbstract:
Key formations throughout the North Perth Basin have been mapped from 3D and 2D seismic data to define depth grid inputs to a 3D basin model calibrated with temperature and maturity data from 45 wells, plus an additional 27 pseudo well models. The Permian Carynginia Formation and Early Triassic Hovea Member of the Kockatea Shale have been defined in this model as unconventional shale reservoir targets. Basin-wide pyrolysis data have been used to construct kinetics curves for both the Carynginia Formation and Kockatea Shale, which define Type D/E and mixed B, and D/E kerogen types, respectively. When combined with thermal history inputs, these source rocks expel and retain significant volumes of hydrocarbons, of which the free hydrocarbons in the retained components reach 22 BCF/km2 for the Carynginia Formation gas and 8 MMBBLS/km2 and 21 BCF/km2 for the Hovea Member liquids and gas, respectively. The defined kinetics relationships allow the estimation of kerogen-specific oil and gas windows, which have been applied across the study area to map unconventional play fairways for both formations, and to calculate the initial total organic carbon (TOC) and hydrogen index (HI) for each unit prior to significant maturation. This study employs a mass balance approach through basin modelling as a means of estimating likely retained hydrocarbon volumes in key unconventional reservoirs in the basin. Sonic and density data from 28 wells in the basin have been used to calculate theoretical porosity to determine likely areas of overpressure. When combined with observed connection gas peaks and modelled maturity, there is a reasonable correlation suggesting that the basin exhibits modest overpressure of 2–6 MPa associated with the main gas window at 1.2 Ro% and this observation is applied to the play fairway mapping process. Play fairways are further constrained through geomechanical and stress considerations from mechanical earth models (MEMs) built from log and image data for wells in the basin. These data define an overall strike-slip stress regime with SHmax consistently oriented east to west with the exception of local perturbations. Dynamic rock strength calculated from the same MEM process shows target zones in the Kockatea Shale and Carynginia Formation ranging from ~60–130 MPa unconfined compressive strength (UCS), calibrated against available static data. The net thickness of rock with a UCS >75 MPa is mapped and overlain on retained in place hydrocarbon maps to restrict the area of likely economically extractable resource. While unconventional play cut-offs in the Perth Basin are notably lower than those commonly used in shale gas plays in the US, successful stimulation of Perth Basin rocks has been demonstrated by substantial flows from wells such as Arrowsmith–2. This study outlines a new workflow for mapping unconventional resources and suggests that Australian rocks are unique in both depositional environment and mechanical properties such that unconventional assessment using US play cut-offs may be misleading.
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Osuya, N. E., and J. O. Ayorinde. "Hydrocarbon Reservoir Characterization of ‘UDI’ Field, Western Niger Delta." Journal of Geography, Environment and Earth Science International, March 18, 2020, 12–21. http://dx.doi.org/10.9734/jgeesi/2020/v24i230198.
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The increasing demand for petroleum products has posed a challenge to the search for oil and gas. This search for hydrocarbon has developed due to advances in computational techniques to evaluate the probability of hydrocarbon proneness of a basin, thereby limiting the risk factor associated with hydrocarbon. This study was therefore designed to assess the hydrocarbon potential and generate a static reservoir model of UDI Field, Onshore Niger Delta.
Well, the correlation was carried out to establish stratigraphic continuity of the reservoir sand bodies. The identified potential reservoir intervals were tied to the seismic data using available check shot survey data. With a good match achieved, seismic events were interpreted through paying attention to reflection continuity, amplitude and frequency. Interpreted horizons were converted to surfaces using a convergent interpolation algorithm. Faults within the Field showed a dominant East-West trend with two (2) major faults and five (5) minor ones. A Pixel-based facies model was built based on the normal distribution of the upscaled lithofacies log using the Sequential Indicator Simulation algorithm. Petrophysical models were built by constraining the petrophysical logs to the facies models using Sequential Gaussian simulation algorithm.
Four potential reservoir intervals, A100, A125, A150 and A200 were delineated. Average petrophysical parameters were computed for all the four intervals and the results revealed the reservoir intervals to be of good quality. Sand A100 has the highest average porosity value of 29.4%, while Sand A200 has the lowest value of 25.3%. Net-to-gross ratio also follows the pattern of decreasing value with depth. Sand A150 has the highest average gross thickness value, 170.4 m, while Sand A200 has the least thickness of 80.5 m. The net-to-gross ratio preserved the pattern of gross thickness and this resulted in Sand A150 still having the highest Net thickness and Sand A200 having the least Net sand thickness. The relatively large net sand thicknesses, high net-to-gross ratio values and the high porosity values all support the reservoir intervals within UDI Field to be of good quality.
Extrapolations of reservoir properties away from good control honored the geological interpretation of reservoir Sand A125 thereby reducing the subsurface reservoir uncertainties.
The availability of pressure data of the reservoir will help in establishing whether the reservoir is compartmentalized and hence the model can be updated to accommodate the effect of compartmentalization.
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Akinsete, Oluwatoyin O., Toyin Y. Abdulraheem, Salawu B. Naheem, and Adebiyi S. Leke. "Integration and Interpretation of Aeromagnetic, 3D Seismic and Well Logs Data in Hydrocarbon Exploration in Niger Delta Basin." Advances in Research, July 15, 2020, 28–42. http://dx.doi.org/10.9734/air/2020/v21i830224.
Full textAbstract:
As the challenges associated with hydrocarbon exploration rises with upsurge in energy demand, the need to minimize risk associated with hydrocarbon exploration if supply is to keep up with demand.
In this work, high resolution aeromagnetic, 3D seismic and well-logs data were adopted and integrated to aid in exploration and characterization of reservoirs in ''XYZ'' field in offshore Niger Delta. Fast Fourier Transform Filter using Oasis Montaj software was applied to the Total Magnetic Intensity grid in horizon and fault interpretation also used to produce subsurface structural maps for sedimentary layer thickness estimation. Direct hydrocarbon indicators (bright spots) on the seismic section was shown using seismic signal. Petrel software and wireline log signatures were used to identify hydrocarbon-bearing sands and determine petrophysical parameters such as porosity, hydrocarbon saturation and net thickness.
The structural maps generated showed: Three major (synthetic) faults dips south and one minor (antithetic) fault dips north in the field; three identified prospective sands (A, B, C) were delineated. Possible presence of oil accumulation was indicated by the combined Neutron-Density log response. The range of values of effective porosity, hydrocarbon saturation and net thickness were 18-22%, 34-58% and 19.1-28.1 m, respectively.
This study established that integration of magnetic, 3D seismic and well-log data are desirable innovative techniques to better understand and analyze subsurface for hydrocarbon potential and exploration.
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Jasim, Nagham, Sameera M. Hamd-Allah, and Hazim Abass. "Specifying Quality of a Tight Oil Reservoir through 3-D Reservoir Modeling." Iraqi Journal of Science, December 30, 2020, 3252–65. http://dx.doi.org/10.24996/ijs.2020.61.12.14.
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Increasing hydrocarbon recovery from tight reservoirs is an essential goal of oil industry in the recent years. Building real dynamic simulation models and selecting and designing suitable development strategies for such reservoirs need basically to construct accurate structural static model construction. The uncertainties in building 3-D reservoir models are a real challenge for such micro to nano pore scale structure. Based on data from 24 wells distributed throughout the Sadi tight formation. An application of building a 3-D static model for a tight limestone oil reservoir in Iraq is presented in this study. The most common uncertainties confronted while building the model were illustrated. Such as accurate estimations of cut-off permeability and porosity values. These values directly affect the calculation of net pay thickness for each layer in the reservoir and consequently affect the target of estimating reservoir initial oil in place (IOIP). Also, the main challenge to the static modeling of such reservoirs is dealing with tight reservoir characteristics which cause major reservoir heterogeneity and complexities that are problematic to the process of modeling reservoir simulation. Twenty seven porosity and permeability measurements from Sadi/Tanuma reservoir were used to validate log interpretation data for model construction. The results of the history matching process of the constructed dynamic model is also presented in this paper, including data related to oil production, reservoir pressure, and well flowing pressure due to available production.
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Bjerager, Morten, Claus Kjøller, Mette Olivarius, Dan Olsen, and Niels H. Schovsbo. "Sedimentology, geochemistry and reservoir properties of Upper Jurassic deep marine sediments (Hareelv Formation) in the Blokelv-1 borehole, Jameson Land Basin, East Greenland." Geological Survey of Denmark and Greenland Bulletin, December 28, 2018, 39–64. http://dx.doi.org/10.34194/geusb.v42.4309.
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The fully cored Blokelv-1 borehole was drilled through Upper Jurassic strata in the central part of the Jameson Land Basin, central East Greenland. The borehole reached a total depth of 233.8 m with nearly 100% recovery of high-quality core. An extensive analytical programme was undertaken on the core; sedimentological interpretation and reservoir characterisation were based on facies analysis combined with conventional core analysis, bulk geochemistry and spectral gamma and density scanning of the core. The Upper Jurassic Hareelv Formation was deposited in relatively deep water in a slope-to-basin setting where background sedimentation was dominated by suspension settling of organic-rich mud in oxygen-depleted conditions. Low- and high-density gravity-flow sandstone interbeds occur throughout the cored succession. About two-thirds of the high-density turbidite sandstones were remobilised and injected into the surrounding mud-rock. The resulting succession comprises nearly equal amounts of mudstones and sandstones in geometrically complex bodies. Ankerite cementation occurs in 37% of the analysed sandstones in varying amounts from minor to pervasive. Such ankerite-cemented sandstones can be identified by their bulk geochemistry where Ca > 2 wt%, Mg > 1 wt% and C > 1 wt%. The analysed mudstones are rich in Al, Fe, Ti and P and poor in Ca, Mg, Na and Mn. The trace-metal content shows a general increase in the upper part of the core reflecting progressive oxygen depletion at the sea floor. The reservoir properties of the Blokelv-1 sandstones were evaluated by both conventional core analysis and using log-derived porosity and permeability curves. The high-density turbidite beds and injectite bodies are a few centimetres to several metres thick and show large variations in porosity and permeability, in the range of 6–26 % for porosity and 0.05–400 mD for permeability. Individual sandstone units that are 1–7 m thick yield a net vertical reservoir thickness of 40 m with porosities of 15–26% and permeabilities of 1–200 mD. Heterolithic sandstone–mudstone units are generally characterised by poor reservoir quality with porosities of 2–14% and permeabilities of 0.1–0.6 mD.
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Wali, Sarah Taboor, and Hussain Ali Baqer. "A Practical Method to Calculate and Model the Petrophysical Properties of Reservoir Rock Using Petrel Software: A case Study from Iraq." Iraqi Journal of Science, October 28, 2020, 2640–50. http://dx.doi.org/10.24996/ijs.2020.61.10.20.
Full textAbstract:
Nasiriyah oilfield is located in the southern part of Iraq. It represents one of the promising oilfields. Mishrif Formation is considered as the main oil-bearing carbonate reservoir in Nasiriyah oilfield, containing heavy oil (API 25o(. The study aimed to calculate and model the petrophysical properties and build a three dimensional geological model for Mishrif Formation, thus estimating the oil reserve accurately and detecting the optimum locations for hydrocarbon production.
Fourteen vertical oil wells were adopted for constructing the structural and petrophysical models. The available well logs data, including density, neutron, sonic, gamma ray, self-potential, caliper and resistivity logs were used to calculate the petrophysical properties. The interpretations and environmental corrections of these logs were performed by applying Techlog 2015 software. According to the petrophysical properties analysis, Mishrif Formation was divided into five units (Mishrif Top, MA, shale bed, MB1 and MB2). A three-dimensional geological model, which represents an entrance for the simulation process to predict reservoir behavior under different hydrocarbon recovery scenarios, was carried out by employing Petrel 2016 software. Models for reservoir characteristics (porosity, permeability, net to gross NTG and water saturation) were created using the algorithm of Sequential Gaussian Simulation (SGS), while the variogram analysis was utilized as an aid to distribute petrophysical properties among the wells.
The process showed that the main reservoir unit of Mishrif Formation is MB1 with a high average porosity of 20.88% and a low average water saturation of 16.9%. MB2 unit has good reservoir properties characterized by a high average water saturation of 96.25%, while MA was interpreted as a water-bearing unit. The impermeable shale bed unit is intercalated between MA and MB1 units with a thickness of 5-18 m, whereas Mishrif top was interpreted as a cap unit. The study outcomes demonstrated that the distribution accuracy of the petrophysical properties has a significant impact on the constructed geological model which provided a better understanding of the study area’s geological construction. Thus, the estimated reserve h was calculated to be about 7945 MSTB. This can support future reservoir development plans and performance predictions.