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K. J. Webb - One of the best experts on this subject based on the ideXlab platform.
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Resource Description and Development Potential of the Ugnu Reservoir, North Slope, Alaska
SPE Formation Evaluation, 1992Co-Authors: R. J. Hallam, E. J. Piekenbrock, Ahmed S. Abou-sayed, A. M. Garon, T. W. Putnam, M. C. Weggeland, K. J. WebbAbstract:Summary The Ugnu deposit, located on the North Slope of Alaska, contains more than 6 billion bbl [954 × 106 m 3] of Oil in place (OIP) in the Kuparuk area. The Oil has been biodegraded. At reservoir temperature, the Dead-Oil Viscosity varies from 100,000 to 10,000,000 cp [100 to 10 000 Pa·s]. The paper provides reservoir and geological descriptions of the resource and discusses the key aspects affecting development. These aspects include high-temperature formation damage, the projected production performance, and the design considerations for injecting steam through a thick permafrost interval. Introduction The Ugnu Oil sands overlie the West Sak and Kuparuk reservoirs on the Alaskan North Slope. The thickest portion of the Ugnu reservoir is located over the northern portion of the Kuparuk River Unit (KRU) (Fig. 1). The resource extends under the Beaufort Sea to the west and into the Milne Point Unit in the east. Although the Ugnu was discovered more than 20 years ago, until recently its database was extremely limited and consisted of only a few cores and logs taken mostly during drilling to the Kuparuk, the producing zone in both the KRU and the Milne Point Unit. In the early 1980's, delineation and development drilling for the deeper Kuparuk formation provided an initial estimate of the areal extent of the resource. At that time, it was thought that the Ugnu contained between 11 and 19 billion bbl [1.7 and 3 × 109 m3] of Oil having a gravity of 8 to 11° API [1.0 to 0.99 g/m3] and a Viscosity between 10,000 and 100,000 cp [10 and 100 Pa·s]. In the mid- to late 1980' s, drilling of the northern Kuparuk drillsites delineated areas of the deposit with a thick, vertically contiguous sand interval (Fig. 1). Then, an extensive study was undertaken between 1988 and 1990 to quantify the resource quality and to evaluate the development potential of this resource. As part of that program, a dedicated Ugnu well (Well DS2-0B1) was drilled and injection tested in 1989. This paper describes the main findings from that study.
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Resource Description and Development Potential of the Ugnu Reservoir, North Slope, Alaska
Spe Formation Evaluation, 1992Co-Authors: R. J. Hallam, E. J. Piekenbrock, Ahmed S. Abou-sayed, A. M. Garon, T. W. Putnam, M. C. Weggeland, K. J. WebbAbstract:The Ugnu deposit, located on the North Slope of Alaska, contains more than 6 billion bbl (954 {times} 10{sup 6} m{sup 3}) of Oil in place (OIP) in the Kuparuk area. The Oil has been biodegraded. At reservoir temperature, the Dead-Oil Viscosity varies from 100,000 to 10,000,000 cp (100 to 10 000 Pa {center dot} s). The paper provides reservoir and geological descriptions of the resource and discusses the key aspects affecting development. These aspects include high-temperature formation damage, the projected production performance, and the design considerations for injecting steam through a thick permafrost interval.
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Resource description and development potential of the Ugnu reservoir, North Slope, Alaska
1992Co-Authors: R. J. Hallam, E. J. Piekenbrock, Ahmed S. Abou-sayed, A. M. Garon, T. W. Putnam, M. C. Weggeland, K. J. WebbAbstract:The Ugnu deposit, located on the North Slope of Alaska, contains more than 6 billion bbl [954 × 10 6 m 3 ] of Oil in place (OIP) in the Kuparuk area. The Oil has been biodegraded. At reservoir temperature, the Dead-Oil Viscosity varies from 100,000 to 10,000,000 cp [100 to 10 000 Pa.s]. The paper provides reservoir and geological descriptions of the resource and discusses the key aspects affecting development. These aspects include high-temperature formation damage, the projected production performance, and the design considerations for injecting steam through a thick permafrost interval
Abdolhossein Hemmati-sarapardeh - One of the best experts on this subject based on the ideXlab platform.
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Modeling Viscosity of light and intermediate Dead Oil systems using advanced computational frameworks and artificial neural networks
Journal of Petroleum Science and Engineering, 2020Co-Authors: Ehsan Khamehchi, Mohammad Reza Mahdiani, Mohammad Amin Amooie, Abdolhossein Hemmati-sarapardehAbstract:Abstract The Dead Oil Viscosity is a key parameter to numerous reservoir engineering problems such as modeling of (viscously-unstable) flow and transport in hydrocarbon reservoirs, sweep efficiency of enhanced Oil recovery scenarios as well as the breakthrough times of the injected fluid. Prediction of this thermos-physical parameter, however, is of challenge due to nonlinear dependence on reservoir conditions as well as the crude Oil characteristics. Previous studies have attempted to develop predictive empirical correlations or other intelligent models for Dead Oil Viscosity; however, they often suffer from the lack of generality and required accuracy. In this work, based on a comprehensive databank from diverse geological sources, we develop three intelligent models –upon various schemes including simulated annealing programming, artificial neural network, and decision tree– for estimating Dead Oil Viscosity. The latter may be used further for prediction of saturated and under-saturated Oil Viscosity as well. Our models function in wide range of temperatures and Oil API gravity; hence, they can be employed as unified, general-in-purpose frameworks for universal prediction of Dead Oil Viscosity. We compare the resulting novel frameworks with the pre-existing models available in the literature, and demonstrate the superiority of the decision tree-based model over others in terms of statistical (and graphical) error estimates as well as the (physical) validity of the model. The findings of this study can help for better understanding and more accurate management, simulation and prediction in different Oil fields.
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A soft computing approach for the determination of crude Oil Viscosity: Light and intermediate crude Oil systems
Journal of the Taiwan Institute of Chemical Engineers, 2016Co-Authors: Abdolhossein Hemmati-sarapardeh, Babak Aminshahidy, Amin Pajouhandeh, Seyed Hamidreza Yousefi, Seyed Arman Hosseini-kaldozakhAbstract:Abstract Crude Oil Viscosity is a key property needed for petroleum engineering analysis such as evaluation of fluid flow in porous media, reservoir performance, reservoir simulation, etc. This property is traditionally measured through expensive and time consuming laboratory measurements. In this communication, about 1500 Dead Oil Viscosity data points of light and intermediate crude Oil systems from various geological locations have been collected. Afterward, a soft computing approach, namely least square support vector machine (LSSVM), has been utilized to develop two distinct Viscosity models for temperatures below and above 313.15 K. The parameters of these models have been optimized using coupled simulated annealing (CSA) optimization tool. The results of this study indicated that the developed models can predict Dead Oil Viscosity at all temperatures and Oil API gravities with enough accuracy. In addition, statistical and graphical error analyses illustrated that the proposed CSA-LSSCM models outperform all of pre-existing models. Besides, the relevancy factor showed that Oil API gravity has the greatest effect on Dead Oil Viscosity. Finally, the Leverage approach demonstrated that the proposed models are statistically valid and acceptable, and only 2% of the data points may be regarded as the probable outliers.
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Toward reservoir Oil Viscosity correlation
Chemical Engineering Science, 2013Co-Authors: Abdolhossein Hemmati-sarapardeh, Ali Naseri, Khishvand, Amir H. MohammadiAbstract:Abstract Oil Viscosity plays a key role in reservoir simulation and production forecasting, as well as planning thermal enhanced Oil recovery methods and these make its accurate determination necessary. In this communication, the most frequently used Oil Viscosity correlations are evaluated using a large databank of Iranian Oil reservoirs which were measured using a Rolling Ball viscometer (Ruska, series 1602). To evaluate the performance and accuracy of these correlations, statistical and graphical error analyses have been used simultaneously. Three of the most accurate correlations for each region, including Dead Oil Viscosity, Viscosity below bubble point, Viscosity at bubble point and the under-saturated Oil Viscosity, are recommended for Iranian Oil reservoirs. In the last step, four correlations are developed for Iranian Oil reservoirs which have simplified functional format. Furthermore, the input data of the latter correlations are those ones that are easily measured in Oil fields. The ranges of data used to develop these new correlations cover almost all Iranian Oil reservoirs PVT data and consequently they could be reliable for prediction of other Iranian Oil reservoirs Viscosity. These new correlations are consistent across a wide range of parameters and offer increased accuracy than previously published correlations for Viscosity prediction of Iranian Oil reservoirs.
R.j. Drozd - One of the best experts on this subject based on the ideXlab platform.
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New Tools Target Oil Quality Sweetspots in Viscous Oil Accumulations
Spe Reservoir Engineering, 1997Co-Authors: P.c. Smalley, N.s. Goodwin, J.f. Dillon, C.r. Bidinger, R.j. DrozdAbstract:Shallow Oilfields frequently contain Oils that not only have low API gravity and high viscosities, but are also highly variable in terms of these properties. It is thus crucial to gather sufficient Oil quality data to sample a statistical cross section of the Oil population. This paper describes how API gravity and Dead Oil Viscosity can be predicted from geochemical parameters that can be measured on core or sidewall core samples, thus allowing Oil samples to be accessed with greater spatial coverage than could reasonably be achieved with conventional fluid sampling. This technique is demonstrated on cored wells from the large Schrader Bluff viscous Oil accumulation in Milne Point, Alaska. An Oil can inherit a particular API gravity or Viscosity from a variety of causes. Consequently, spatial variations in such bulk Oil properties can be difficult to map empirically simply by contouring data, because more than one controlling factor may be operative. A major step forward in fluid mapping is to identify and quantify these controls, and map them. In Schrader Bluff the controls were discovered to be degree of biodegradation, and the presence of an in-mixed second charge of (light) Oil. Variations in these processes can be mapped withmore » a much greater degree of certainty than the bulk Oil properties, and the individual maps combined to predict gravity and Viscosity. Further, conceptual models exist for these processes, opening the possibility of model-driven prediction of Oil properties and sweetspots in areas away from well control.« less
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New Tools Target Oil Quality Sweetspots in Viscous Oil Accumulations
SPE Reservoir Engineering, 1997Co-Authors: P.c. Smalley, N.s. Goodwin, J.f. Dillon, C.r. Bidinger, R.j. DrozdAbstract:Summary Shallow Oil fields frequently contain Oils that not only have low Oil gravity and high viscosities, but are also highly variable in terms of these properties. It is thus crucial to gather sufficient Oil-quality data to sample a statistical cross section of the Oil population. This paper describes how Oil gravity and Dead-Oil Viscosity can be predicted from geochemical parameters that can be measured on core or sidewall core samples, thus allowing Oil samples to be accessed with greater spatial coverage than could reasonably be achieved with conventional fluid sampling. This technique is demonstrated on cored wells from the large Schrader Bluff viscous Oil accumulation in Milne Point, Alaska. An Oil can inherit a particular Oil gravity or Viscosity for a variety of causes. Consequently, spatial variations in such bulk-Oil properties can be difficult to map empirically simply by contouring data because more than one controlling factor may be operative. A major step forward in fluid mapping is to identify and quantify these controls and map the controls. In Schrader Bluff the controls were discovered to be the degree of biodegradation and the presence of an in-mixed second charge of (light) Oil. Variations in these processes can be tracked with geochemical parameters and mapped with a much greater degree of certainty than the bulk-Oil properties. The resulting individual maps may then be combined to predict Oil gravity and Viscosity. Conceptual models exist for these processes, opening the possibility of model-driven prediction of Oil properties and sweetspots in areas away from well control. Introduction Many shallow Oil accumulations contain Oils that have been affected by microbial processes. This so-called biodegradation results in easily metabolized compounds being progressively stripped from the Oil. The normal alkanes are the first to disappear, followed by more complex cyclic and aromatic compounds. In the most severe cases, all that remains is a tarry mass of chemically unresolvable high-molecular-weight compounds. Progressive biodegradation is accompanied by an increase in Oil density and thus a decrease in Oil gravity. Oil Viscosity increases too, meaning that well flow rates can be a problem and that special stimulation methods may be needed to achieve commercial rates.
Amir H. Mohammadi - One of the best experts on this subject based on the ideXlab platform.
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Toward reservoir Oil Viscosity correlation
Chemical Engineering Science, 2013Co-Authors: Abdolhossein Hemmati-sarapardeh, Ali Naseri, Khishvand, Amir H. MohammadiAbstract:Abstract Oil Viscosity plays a key role in reservoir simulation and production forecasting, as well as planning thermal enhanced Oil recovery methods and these make its accurate determination necessary. In this communication, the most frequently used Oil Viscosity correlations are evaluated using a large databank of Iranian Oil reservoirs which were measured using a Rolling Ball viscometer (Ruska, series 1602). To evaluate the performance and accuracy of these correlations, statistical and graphical error analyses have been used simultaneously. Three of the most accurate correlations for each region, including Dead Oil Viscosity, Viscosity below bubble point, Viscosity at bubble point and the under-saturated Oil Viscosity, are recommended for Iranian Oil reservoirs. In the last step, four correlations are developed for Iranian Oil reservoirs which have simplified functional format. Furthermore, the input data of the latter correlations are those ones that are easily measured in Oil fields. The ranges of data used to develop these new correlations cover almost all Iranian Oil reservoirs PVT data and consequently they could be reliable for prediction of other Iranian Oil reservoirs Viscosity. These new correlations are consistent across a wide range of parameters and offer increased accuracy than previously published correlations for Viscosity prediction of Iranian Oil reservoirs.
Stephen R Larter - One of the best experts on this subject based on the ideXlab platform.
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deterioration of Oil quality during sample storage are stored reservoir core samples a viable resource for Oil Viscosity determination
Fuel, 2019Co-Authors: Barry Bennett, Chunqing Jiang, Stephen R LarterAbstract:Abstract The physical and chemical properties of Oil residing in reservoir core samples are strongly susceptible to evaporative processes during storage. In a case study from the Peace River Oil sands of Alberta, we performed Dead Oil Viscosity measurements on Oils recovered by mechanical extraction of fresh core, the equivalent cores stored for 7 months frozen plus 3 months at ambient conditions (time 1) and for 7 months frozen plus 8 months at ambient conditions (time 2). The Dead Oil Viscosity of Oil recovered from fresh core material (8100 cP at 20 °C) was more than an order of magnitude lower than that of the Oil subsequently recovered from an equivalent core sample stored frozen for 7 months and then at ambient temperature for 8 months (313,500 cP at 20 °C). The evaporation of light hydrocarbons such as toluene and xylenes during storage is a continuous process responsible for progressive increase in Dead Oil Viscosity. Meanwhile, when comparing the Oils recovered from fresh core and aged core samples, the composition of the heavy (low volatility) hydrocarbons remains essentially the same. Because biodegradation is the primary control on Oil Viscosity and variation in hydrocarbon compositions for this Oil sample suite, partial least squares models based on Viscosity versus geochemical data may still be used to predict Viscosity. Although the physical properties of the Oil may be compromised during storage, the distributions of the high molecular weight components retain characteristics, similar to a bar code, that are inherited and representative of the original (fresh) core sample. Therefore, with the proviso that the distributions of high molecular weight components are comparable between fresh cores and aged cores, the Viscosity of Oil residing in stored core samples can be effectively restored by chemometric-based correlation methods.
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a practical method for the separation of high quality heavy Oil and bitumen samples from Oil reservoir cores for physical and chemical property determination
Fuel, 2014Co-Authors: Barry Bennett, Chunqing Jiang, Lloyd R Snowdon, Stephen R LarterAbstract:Abstract We describe a mechanical extraction method, referred to here as “the plunger”, for the recovery of heavy Oil and bitumen samples, equivalent to produced Oil samples, from clastic and carbonate reservoir cores. We demonstrate the efficacy of the plunger relative to the centrifugation method through comparing the physical properties and chemical compositions of the heavy Oils and bitumens recovered from Oil sands cores. Over the Dead Oil Viscosity range from 21,000 cP to 1.4 × 106 cP at 20 °C and 9.6 × 106 cP at 25.5 °C, the plunger consistently yielded correspondingly lower Viscosity Oils compared to the Oils recovered by centrifugation from the same sample material, as well as lower sediment fines and water content. For an example of extremely viscous Oil, the plunger yielded 3.3 g of 9.6 × 106 cP Oil (25.5 °C), while centrifugation produced only 50 mg of fluid, adequate for geochemical analysis but insufficient for Viscosity and density determination. The plunger has many advantages that favor its use over centrifugation such as successful recovery of highly viscous Oil from cores, lower Oil sediment fines/water content and faster sample extraction (typically 30 min to 1 h versus 2 h). The plunger has also been operated at the rig site to generate Oil Viscosity logs immediately following core recovery (prior to or during petrophysical logging) affording real time data acquisition to support decisions for conducting production flow tests while drilling rigs are onsite. Incidentally, due to the improved preservation of physical properties controlling volatile liquid components, repeated plunging of larger volumes of sample core can be used to recover large enough volumes of heavy Oil or bitumen for PVT or specialist assay analysis. Since the plunger is operated under a sealed system the device may be configured in such a way to interface with a PVT cell. Gas introduced into the plunger system ultimately can lead to the production and collection of “enlivened Oils” for Viscosity measurements.