The Experts below are selected from a list of 5523 Experts worldwide ranked by ideXlab platform
Ping Yue - One of the best experts on this subject based on the ideXlab platform.
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a coupling model of water breakthrough time for a multilateral horizontal well in a bottom water Drive Reservoir
Journal of Petroleum Science and Engineering, 2019Co-Authors: Ping Yue, Bingyi Jia, James J Sheng, Tao Lei, Chao TangAbstract:Abstract A series of complex production wells have been applied in challenging Reservoirs to maximize oil recovery. Multilateral horizontal well has received plentiful attentions in recent years. The multilateral horizontal well technology is especially beneficial in expanding formation drainage area, reducing water cresting and coning, increasing productivity, and postponing water breakthrough time in bottom water Reservoir. Since Muskat and Wyckoff introduced the concept of water coning into petroleum engineering field, different models have been proposed to forecast the critical rate and water breakthrough time for vertical and horizontal wells. However, the studies of water breakthrough time for complex structured multilateral horizontal wells have rarely been reported. This paper proposes a new coupling model for estimating the water breakthrough time of complex structured multilateral horizontal wells. The proposed model took multiple factors into account, including the wellbore 3D structure, wellbore vertical location, and Reservoir and fluids properties. In addition, a field case study was conducted by utilizing the methods that were proposed in this paper. The practical production data was compared with the results obtained from the analytical model, and this coupling model shows an excellent agreement with the results from the actual scenarios. The proposed methods in this paper can be utilized to forecast the water breakthrough time and breakthrough locations of multilateral wells in bottom water Reservoirs.
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the critical parameters of a horizontal well influenced by a semi permeable barrier considering thickness in a bottom water Reservoir
Journal of Petroleum Science and Engineering, 2015Co-Authors: Ping Yue, Xiaofan Chen, Haohan Liu, Hu JiaAbstract:Abstract It is well known that barriers have significant impact on the production performance of horizontal wells developed in a bottom water Drive Reservoir. In most cases, Reservoir barriers are semi-permeable. Based on our previous research results on impermeable, semi-permeable barriers that ignore thickness, in this paper, a model is derived for a horizontal well of a bottom water Drive Reservoir with a semi-permeable barrier considering thickness. It also presents analytical equations to calculate critical parameters such as production rate, pressure and potential difference. The effects of barrier parameters on our model results were further investigated. The results showed that the larger the barrier size, thickness or the higher the barrier location, the higher are the critical parameters of a horizontal well. In a case, where the barrier permeability equals the formation permeability, the barrier width or thickness equals zero, the critical production rates converge to the same values of the case that has no barrier. When the barrier permeability equals zero, the problem is regarded as a case of impermeable barrier. This model can be applied to predict horizontal wells׳ critical production parameters in bottom water Reservoirs with different size, thickness, and permeability of semi-permeable barriers.
Chao Tang - One of the best experts on this subject based on the ideXlab platform.
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a coupling model of water breakthrough time for a multilateral horizontal well in a bottom water Drive Reservoir
Journal of Petroleum Science and Engineering, 2019Co-Authors: Ping Yue, Bingyi Jia, James J Sheng, Tao Lei, Chao TangAbstract:Abstract A series of complex production wells have been applied in challenging Reservoirs to maximize oil recovery. Multilateral horizontal well has received plentiful attentions in recent years. The multilateral horizontal well technology is especially beneficial in expanding formation drainage area, reducing water cresting and coning, increasing productivity, and postponing water breakthrough time in bottom water Reservoir. Since Muskat and Wyckoff introduced the concept of water coning into petroleum engineering field, different models have been proposed to forecast the critical rate and water breakthrough time for vertical and horizontal wells. However, the studies of water breakthrough time for complex structured multilateral horizontal wells have rarely been reported. This paper proposes a new coupling model for estimating the water breakthrough time of complex structured multilateral horizontal wells. The proposed model took multiple factors into account, including the wellbore 3D structure, wellbore vertical location, and Reservoir and fluids properties. In addition, a field case study was conducted by utilizing the methods that were proposed in this paper. The practical production data was compared with the results obtained from the analytical model, and this coupling model shows an excellent agreement with the results from the actual scenarios. The proposed methods in this paper can be utilized to forecast the water breakthrough time and breakthrough locations of multilateral wells in bottom water Reservoirs.
Sunday Isehunwa - One of the best experts on this subject based on the ideXlab platform.
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Optimization of Gas Recovery using Co-production technique in Water Drive Reservoir
Journal of Petroleum and Gas Engineering, 2017Co-Authors: A. O. Maselugbo, R. U. Onolemhemhen, Samuel O. Salufu, Adetokunbo O Denloye, Sunday IsehunwaAbstract:Recovery factor for gas Reservoirs are highly dependent on factors such as initial Reservoir pressure, abandonment pressure and the type of Reservoir Drive mechanism. Producing gas Reservoirs with active water Drive mechanism possess a lot of challenge to the field operator since optimum production of gas is dependent on reduced pressure. Material balance model was used to derive basic Reservoir and production parameters thereafter Excel was used to simulate the parameters for both conventional and co-production scenarios using a field data from the Niger Delta Basin. The Reservoir contains three producing wells with conventional technique, while co-production has three wells, producing gas from the up-dip and one well producing water from the down-dip. The simulated results show that gas production rate from the three wells changed with respect to the production strategies. Under conventional, gas production rate from the three wells was at a constant rate of 19MMSCF/D for a long period of time. However, under co-production technique, gas production rate was at a constant rate of 38MMSCF/D for a short period of time. Under conventional method, 231.85BCF of gas was recovered from 356.713BCF of gas initially-in-place with recovery factor of 65% until water cut set-in at an abandonment pressure of 2000 psia. However, under co-production technique, the simulated result shows that there was an optimum recovery of gas of up to 92% recovery which is 27% above the conventional technique and the Reservoir pressure was depleted to 1000 psia before water cut set-in. Key words: Co-production, Niger Delta Basin, gas production, material balance model, gas Reservoir.
Curtis M. Oldenburg - One of the best experts on this subject based on the ideXlab platform.
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carbon sequestration in natural gas Reservoirs enhanced gas recovery and natural gas storage
Lawrence Berkeley National Laboratory, 2003Co-Authors: Curtis M. OldenburgAbstract:Natural gas Reservoirs are obvious targets for carbon sequestration by direct carbon dioxide (CO2) injection by virtue of their proven record of gas production and integrity against gas escape. Carbon sequestration in depleted natural gas Reservoirs can be coupled with enhanced gas production by injecting CO2 into the Reservoir as it is being produced, a process called Carbon Sequestration with Enhanced Gas Recovery (CSEGR). In this process, supercritical CO2 is injected deep in the Reservoir while methane (CH4) is produced at wells some distance away. The active injection of CO2 causes repressurization and CH4 displacement to allow the control and enhancement of gas recovery relative to water-Drive or depletion-Drive Reservoir operations. Carbon dioxide undergoes a large change in density as CO2 gas passes through the critical pressure at temperatures near the critical temperature. This feature makes CO2 a potentially effective cushion gas for gas storage Reservoirs. Thus at the end of the CSEGR process when the Reservoir is filled with CO2, additional benefit of the Reservoir may be obtained through its operation as a natural gas storage Reservoir. In this paper, we present discussion and simulation results from TOUGH2/EOS7C of gas mixture property prediction, gas injection, repressurization, migration, and mixing processes that occur in gas Reservoirs under active CO2 injection.
Yanil Del Castillo Maravi - One of the best experts on this subject based on the ideXlab platform.
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New inflow performance relationships for gas condensate Reservoirs
2004Co-Authors: Yanil Del Castillo MaraviAbstract:New Inflow Performance Relationships for Gas Condensate Reservoirs. (August 2003) Yanil Del Castillo Maravi, B.S., Universidad Nacional de Ingenieria Co-Chairs of Advisory Committee: Dr. Rosalind A. Archer Dr. Thomas A. Blasingame In this work we propose two new Vogel-type Inflow Performance Relations (or IPR) correlations for gascondensate Reservoir systems. One correlation predicts dry gas production the other predicts condensate (liquid) production. These correlations provide a linkage between Reservoir rock and fluid properties (dewpoint, temperature, and endpoint relative permeabilities, composition, etc.) to the flowrate-pressure performance for the Reservoir system. The proposed IPR relationships for compositional Reservoir systems are based on data from over 3000 compositional Reservoir simulation cases developed using various fluid properties and relative permeability curves. The resulting IPR curves for gas condensate systems are quadratic in behavior — similar to the Vogel IPR trends (the Vogel (quadratic) rate-pressure profile is generally presumed for the case of a solution gas-Drive Reservoir system). However, in the case of a gas-condensate Reservoir system, the coefficients in the quadratic relationship vary significantly depending on the richness of the gas condensate fluid (i.e., the composition) as well as the relative permeability-saturation behavior. Using an alternating conditional expectation approach (i.e., non-parametric regression), an approximate model was developed to estimate these coefficients. This work also includes a discussion of the Vogel IPR for solution gas-Drive systems. The original work proposed by Vogel is based on an empirical correlation of numerical simulations for a solution-gas-Drive system. Our work provides a critical validation and extension of the Vogel work by establishing a simple, yet rigorous formulation for flowrate-pressure performance in terms of effective permeabilities and pressure-dependent fluid properties. The direct application of this work is to predict the IPR for a given Reservoir system directly from rockfluid properties and fluid properties. This formulation provides a new mechanism that can be used to couple the flowrate and pressure behavior for solution gas-Drive systems and we believe that it may be possible to extend the proposed semi-analytical concept to gas-condensate Reservoir systems. However, for this work we have only considered a semi-empirical IPR approach (i.e., a data-derived correlation) for the case of gas-condensate Reservoir systems. We recognize that further work should be performed in this area, and we encourage future research on the topic of semi-analytical modeling of IPR behavior for gascondensate Reservoir systems.
