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Journal articles on the topic 'Gas condensate reservoirs. Gas condensate reservoirs'

Author: Grafiati

Published: 4 June 2021

Last updated: 7 February 2022

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1

Chen, H. L., S. D. Wilson, and T. G. Monger-McClure. "Determination of Relative Permeability and Recovery for North Sea Gas-Condensate Reservoirs." SPE Reservoir Evaluation & Engineering 2, no. 04 (1999): 393–402. http://dx.doi.org/10.2118/57596-pa.

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Summary Coreflood experiments on gas condensate flow behavior were conducted for two North Sea gas condensate reservoirs. The objectives were to investigate the effects of rock and fluid characteristics on critical condensate saturation (CCS), gas and condensate relative permeabilities, hydrocarbon recovery and trapping by water injection, and incremental recovery by subsequent blowdown. Both CCS and relative permeability were sensitive to flow rate and interfacial tension. The results on gas relative permeability rate sensitivity suggest that gas productivity curtailed by condensate dropout c

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2

Hu, Wen Ge, Xiang Fang Li, Xin Zhou Yang, Ke Liu Wu, and Jun Tai Shi. "Energy Control in the Depletion of Gas Condensate Reservoirs with Different Permeabilities." Advanced Materials Research 616-618 (December 2012): 796–803. http://dx.doi.org/10.4028/www.scientific.net/amr.616-618.796.

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Energy control (i. e. pressure control) has an obvious effect on development effect in the depletion of gas condensate reservoir. Phase change behavior and characteristics of the relative pemeability in gas condensate reservoirs were displayed in this paper, then pressure and condensate distribution were showed through reservoir simulation. Finally, the influence of the pressure drop on condensate distribution and condensate oil production in gas condensate reservoirs with different permeabilities was studied. Results show that: First, in high / moderate permeability gas condensate reservoirs,

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3

Panja, Palash, and Milind Deo. "Factors That Control Condensate Production From Shales: Surrogate Reservoir Models and Uncertainty Analysis." SPE Reservoir Evaluation & Engineering 19, no. 01 (2015): 130–41. http://dx.doi.org/10.2118/179720-pa.

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Summary Rapid development of shales for the production of oils and condensates may not be permitting adequate analysis of the important factors governing recovery. Understanding the performance of shales or tight oil reservoirs producing condensates requires numerically extensive compositional simulations. The purpose of this study is to identify important factors that control production of condensates from low-permeability plays and to develop analytical “surrogate” models suitable for Monte Carlo analysis. In this study, the surrogate reservoir models were second-order response surfaces func

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4

Meng, Xingbang, Zhan Meng, Jixiang Ma, and Tengfei Wang. "Performance Evaluation of CO2 Huff-n-Puff Gas Injection in Shale Gas Condensate Reservoirs." Energies 12, no. 1 (2018): 42. http://dx.doi.org/10.3390/en12010042.

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When the reservoir pressure is decreased lower than the dew point pressure in shale gas condensate reservoirs, condensate would be formed in the formation. Condensate accumulation severely reduces the commercial production of shale gas condensate reservoirs. Seeking ways to mitigate condensate in the formation and enhance both condensate and gas recovery in shale reservoirs has important significance. Very few related studies have been done. In this paper, both experimental and numerical studies were conducted to evaluate the performance of CO2 huff-n-puff to enhance the condensate recovery in

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Shams, Bilal, Jun Yao, Kai Zhang, and Lei Zhang. "Sensitivity analysis and economic optimization studies of inverted five-spot gas cycling in gas condensate reservoir." Open Physics 15, no. 1 (2017): 525–35. http://dx.doi.org/10.1515/phys-2017-0060.

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AbstractGas condensate reservoirs usually exhibit complex flow behaviors because of propagation response of pressure drop from the wellbore into the reservoir. When reservoir pressure drops below the dew point in two phase flow of gas and condensate, the accumulation of large condensate amount occurs in the gas condensate reservoirs. Usually, the saturation of condensate accumulation in volumetric gas condensate reservoirs is lower than the critical condensate saturation that causes trapping of large amount of condensate in reservoir pores. Trapped condensate often is lost due to condensate ac

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Bilotu Onoabhagbe, Benedicta, Paul Russell, Johnson Ugwu, and Sina Rezaei Gomari. "Application of Phase Change Tracking Approach in Predicting Condensate Blockage in Tight, Low, and High Permeability Reservoirs." Energies 13, no. 24 (2020): 6551. http://dx.doi.org/10.3390/en13246551.

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Prediction of the timing and location of condensate build-up around the wellbore in gas condensate reservoirs is essential for the selection of appropriate methods for condensate recovery from these challenging reservoirs. The present work focuses on the use of a novel phase change tracking approach in monitoring the formation of condensate blockage in a gas condensate reservoir. The procedure entails the simulation of tight, low and high permeability reservoirs using global and local grid analysis in determining the size and timing of three common regions (Region 1, near wellbore; Region 2, c

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Hou, Dali, Yang Xiao, Yi Pan, Lei Sun, and Kai Li. "Experiment and Simulation Study on the Special Phase Behavior of Huachang Near-Critical Condensate Gas Reservoir Fluid." Journal of Chemistry 2016 (2016): 1–10. http://dx.doi.org/10.1155/2016/2742696.

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Due to the special phase behavior of near-critical fluid, the development approaches of near-critical condensate gas and near-critical volatile oil reservoirs differ from conventional oil and gas reservoirs. In the near-critical region, slightly reduced pressure may result in considerable change in gas and liquid composition since a large amount of gas or retrograde condensate liquid is generated. It is of significance to gain insight into the composition variation of near-critical reservoir during the depletion development. In our study, we performed a series ofPVTexperiments on a real near-c

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8

Ayala, Luis F., Turgay Ertekin, and Michael A. Adewumi. "Compositional Modeling of Retrograde Gas-Condensate Reservoirs in Multimechanistic Flow Domains." SPE Journal 11, no. 04 (2006): 480–87. http://dx.doi.org/10.2118/94856-pa.

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Summary A multimechanistic flow environment is the result of the combined action of a Darcian flow component (the macroscopic flow of the phase caused by pressure gradients) and a Fickian-like or diffusive flow component (diffusive flow caused by molecular concentration gradients) taking place in a hydrocarbon reservoir. The present work presents the framework needed for the assessment of the impact of multimechanistic flow on systems where complex fluid behavior—such as that of retrograde gas-condensate fluids—requires the implementation of compositional reservoir simulators. Because of the c

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9

Onoabhagbe, Gomari, Russell, Ugwu, and Ubogu. "Phase Change Tracking Approach to Predict Timing of Condensate Formation and its Distance from the Wellbore in Gas Condensate Reservoirs." Fluids 4, no. 2 (2019): 71. http://dx.doi.org/10.3390/fluids4020071.

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Production from gas condensate reservoir poses the major challenge of condensate banking or blockage. This occurs near the wellbore, around which a decline in pressure is initially observed. A good sign of condensate banking is a rise in the gas–oil ratio (GOR) during production and/or a decline in the condensate yield of the well, which leads to considerable reductions in well deliverability and well rate for gas condensate reservoirs. Therefore, determining the well deliverability of a gas condensate reservoir and methods to optimize productivity is paramount in the industry.

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10

Lopez Jimenez, Bruno A., and Roberto Aguilera. "Flow Units in Shale Condensate Reservoirs." SPE Reservoir Evaluation & Engineering 19, no. 03 (2016): 450–65. http://dx.doi.org/10.2118/178619-pa.

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Summary Recent work has shown that flow units characterized by process or delivery speed (the ratio of permeability to porosity) provide a continuum between conventional, tight-gas, shale-gas, tight-oil, and shale-oil reservoirs (Aguilera 2014). The link between the various hydrocarbon fluids is provided by the word “petroleum” in “Total Petroleum System” (TPS), which encompasses liquid and gas hydrocarbons found in conventional, tight, and shale reservoirs. The work also shows that, other things being equal, the smaller pores lead to smaller production rates. There is, however, a positive sid

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11

Fishlock, T. P., and C. J. Probert. "Waterflooding of Gas Condensate Reservoirs." SPE Reservoir Engineering 11, no. 04 (1996): 245–51. http://dx.doi.org/10.2118/35370-pa.

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12

Song, Heng, Zi Fei Fan, Lun Zhao, and An Gang Zhang. "Gas Cap and Oil Rim Collaborative Development Technique Policy of Carbonate Reservoir with Condensate Gas Cap." Advanced Materials Research 734-737 (August 2013): 1381–90. http://dx.doi.org/10.4028/www.scientific.net/amr.734-737.1381.

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Zhanazhol oilfield is a large-scale complicated carbonated oil and gas field , Гnorth is the main oil and gas reservoirs of the oil field, The gas cap index is 0.38, the gas cap on a high condensate content. Reservoir development for nearly 25 years, exploitation in the past only to oil ring. Due to insufficient water injection in early age, the oil ring pressure dropped substantially, and the formation pressure to maintain the level of only 58%. For oil and gas reservoirs with a condensate gas cap, gas cap and oil ring at the same pressure system, with the decline in the pressure of the oil r

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Mott, R. E., A. S. Cable, and M. C. Spearing. "Measurements of Relative Permeabilities for Calculating Gas-Condensate Well Deliverability." SPE Reservoir Evaluation & Engineering 3, no. 06 (2000): 473–79. http://dx.doi.org/10.2118/68050-pa.

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Summary Well deliverability in many gas-condensate reservoirs is reduced by condensate banking when the bottomhole pressure falls below the dewpoint, although the impact of condensate banking may be reduced due to improved mobility at high capillary number in the near-well region. This paper presents the results of relative permeability measurements on a sandstone core from a North Sea gas-condensate reservoir, at velocities that are typical of the near-well region. The results show a clear increase in mobility with capillary number, and the paper describes how the data can be modeled with emp

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14

Huang, Quan Hua, and Xing Yu Lin. "Prediction of water breakthrough time in horizontal Wells in edge water condensate gas reservoirs." E3S Web of Conferences 213 (2020): 02009. http://dx.doi.org/10.1051/e3sconf/202021302009.

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Horizontal Wells are often used to develop condensate gas reservoirs. When there is edge water in the gas reservoir, it will have a negative impact on the production of natural gas. Therefore, reasonable prediction of its water breakthrough time is of great significance for the efficient development of condensate gas reservoirs.At present, the prediction model of water breakthrough time in horizontal Wells of condensate gas reservoir is not perfect, and there are mainly problems such as incomplete consideration of retrograde condensate pollution and inaccurate determination of horizontal well

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15

Henderson, G. D., A. Danesh, D. H. Tehrani, S. Al-Shaidi, and J. M. Peden. "Measurement and Correlation of Gas Condensate Relative Permeability by the Steady-State Method." SPE Reservoir Evaluation & Engineering 1, no. 02 (1998): 134–40. http://dx.doi.org/10.2118/30770-pa.

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Abstract High pressure core flood experiments using gas condensate fluids in long sandstone cores have been conducted. Steady-state relative permeability points were measured over a wide range of condensate to gas ratio's (CGR), with the velocity and interfacial tension (IFT) being varied between tests in order to observe the effect on relative permeability. The experimental procedures ensured that the fluid distribution in the cores was representative of gas condensate reservoirs. Hysteresis between drainage and imbibition during the steady-state measurements was also investigated, as was the

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Jukić, Lucija, Domagoj Vulin, Valentina Kružić, and Maja Arnaut. "Carbon-Negative Scenarios in High CO2 Gas Condensate Reservoirs." Energies 14, no. 18 (2021): 5898. http://dx.doi.org/10.3390/en14185898.

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A gas condensate reservoir in Northern Croatia was used as an example of a CO2 injection site during natural gas production to test whether the entire process is carbon-negative. To confirm this hypothesis, all three elements of the CO2 life cycle were included: (1) CO2 emitted by combustion of the produced gas from the start of production from the respective field, (2) CO2 that is separated at natural gas processing plant, i.e., the CO2 that was present in the original reservoir gas composition, and (3) the injected CO2 volumes. The selected reservoir is typical of gas-condensate reservoirs i

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17

Safari-Beidokhti, Mohsen, Abdolnabi Hashemi, Reza Abdollahi, Hamed Hematpur, and Hamid Esfandyari. "Numerical Well Test Analysis of Condensate Dropout Effects in Dual-Permeability Model of Naturally Fractured Gas Condensate Reservoirs: Case Studies in the South of Iran." Mathematical Problems in Engineering 2021 (May 7, 2021): 1–10. http://dx.doi.org/10.1155/2021/9916914.

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Naturally fractured reservoirs (NFR) represent an important percentage of worldwide hydrocarbon reserves and production. The performance of naturally fractured gas condensate reservoirs would be more complicated regarding both rock and fluid effects. In contrast to the dual-porosity model, dual-porosity/dual-permeability (dual-permeability) model is considered as a modified model, in which flow to the wellbore occurs through both matrix and fracture systems. Fluid flow in gas condensate reservoirs usually demonstrates intricate flow behavior when the flowing bottom-hole pressure falls below th

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18

Burachok, Oleksandr. "Enhanced Gas and Condensate Recovery: Review of Published Pilot and Commercial Projects." Nafta-Gaz 77, no. 1 (2021): 20–25. http://dx.doi.org/10.18668/ng.2021.01.03.

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The majority of the Ukrainian gas condensate fields are in the final stage of development. The high level of reservoir energy depletion has caused significant in situ losses of condensed hydrocarbons. Improving and increasing hydrocarbon production is of great importance to the energy independence of Ukraine. In this paper, a review of the pilot and commercial enhanced gas and condensate recovery (EGR) projects was performed, based on published papers and literature sources, in order to identify those projects which could potentially be applied to the reservoir conditions of Ukrainian gas cond

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19

Mohan, Jitendra, Gary A. Pope, and Mukul M. Sharma. "Effect of Non-Darcy Flow on Well Productivity of a Hydraulically Fractured Gas-Condensate Well." SPE Reservoir Evaluation & Engineering 12, no. 04 (2009): 576–85. http://dx.doi.org/10.2118/103025-pa.

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Summary Hydraulic fracturing is a common way to improve productivity of gas-condensate wells. Previous simulation studies have predicted much larger increases in well productivity than have been actually observed in the field. This paper shows the large impact of non-Darcy flow and condensate accumulation on the productivity of a hydraulically fractured gas-condensate well. Two-level local-grid refinement was used so that very small gridblocks corresponding to actual fracture width could be simulated. The actual fracture width must be used to accurately model non-Darcy flow. An unrealistically

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Goldthorpe, W. H., and J. K. Drohm. "APPLICATION OF THE BLACK OIL PVT REPRESENTATION TO SIMULATION OF GAS CONDENSATE RESERVOIR PERFORMANCE." APPEA Journal 27, no. 1 (1987): 370. http://dx.doi.org/10.1071/aj86032.

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Special attention must be paid to the generation of PVT parameters when applying conventional black oil reservoir simulators to the modelling of volatile oil and gas-condensate reservoirs. In such reservoirs phase behaviour is an important phenomenon and common approaches to approximating this, via the black oil PVT representation, introduce errors that may result in prediction of incorrect recoveries of surface gas and condensate. Further, determination of production tubing pressure drops for use in such simulators is also prone to errors. These affect the estimation of well potentials and re

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Høier, Lars, and Curtis H. Whitson. "Miscibility Variation in Compositionally Grading Reservoirs." SPE Reservoir Evaluation & Engineering 4, no. 01 (2001): 36–43. http://dx.doi.org/10.2118/69840-pa.

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Summary Minimum miscibility conditions of pressure and enrichment (MMP/MME) have been computed with an equation of state (EOS) for several reservoir-fluid systems exhibiting compositional gradients with depth owing to gravity/chemical equilibrium. MMP/MME conditions are calculated with a multicell algorithm developed by Aaron Zick, where the condensing/vaporizing (C/V) mechanism of developed miscibility is used as the true measure of minimum miscibility conditions when it exists. The Zick algorithm is verified by detailed one-dimensional (1D) slimtube simulations with elimination of numerical

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Hassan, Amjed M., Mohamed A. Mahmoud, Abdulaziz A. Al-Majed, Dhafer Al-Shehri, Ayman R. Al-Nakhli, and Mohammed A. Bataweel. "Gas Production from Gas Condensate Reservoirs Using Sustainable Environmentally Friendly Chemicals." Sustainability 11, no. 10 (2019): 2838. http://dx.doi.org/10.3390/su11102838.

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Unconventional reservoirs have shown tremendous potential for energy supply for long-term applications. However, great challenges are associated with hydrocarbon production from these reservoirs. Recently, injection of thermochemical fluids has been introduced as a new environmentally friendly and cost-effective chemical for improving hydrocarbon production. This research aims to improve gas production from gas condensate reservoirs using environmentally friendly chemicals. Further, the impact of thermochemical treatment on changing the pore size distribution is studied. Several experiments we

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23

Chen, Junqing, Xiongqi Pang, and Zhenxue Jiang. "Controlling factors and genesis of hydrocarbons with complex phase state in the Upper Ordovician of the Tazhong Area, Tarim Basin, China." Canadian Journal of Earth Sciences 52, no. 10 (2015): 880–92. http://dx.doi.org/10.1139/cjes-2014-0209.

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Seven hydrocarbon reservoirs have been discovered to date in the Upper Ordovician of the Tazhong Area, a region in which hydrocarbon phase distribution is complex. In the present study, the genesis and controlling factors of the hydrocarbons with complex phase in the Tazhong Area were investigated on the basis of the geological and geochemical conditions required for the formation and distribution of hydrocarbon reservoirs, integrated with the source rock geochemistry, natural gas and oil properties, and oil and gas reservoir fluid tests PVT (i.e., pressure, volume, and temperature tests). The

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Wang, Zhenliang, Shengdong Xiao, Feilong Wang, Guomin Tang, Liwen Zhu, and Zilong Zhao. "Phase Behavior Identification and Formation Mechanisms of the BZ19-6 Condensate Gas Reservoir in the Deep Bozhong Sag, Bohai Bay Basin, Eastern China." Geofluids 2021 (July 2, 2021): 1–19. http://dx.doi.org/10.1155/2021/6622795.

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Significant developments have been observed in recent years, in the field of deep part exploration in the Bozhong Sag, Bohai Bay Basin in eastern China. The BZ19-6 large condensate gas field, the largest gas field in the Bohai Bay Basin, was discovered for the first time in a typical oil-type basin. The proven oil and gas geological reserves in the deeply buried hills of the Archean metamorphic rocks, amount to approximately 3 × 10 8 tons of oil equivalent. However, the phase behavior and genetic mechanisms of hydrocarbon fluids are still unclear. In this study, the phase diagram identificatio

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Al-Meshari, Ali A., Sunil L. Kokal, Peter D. Jenden, and Henry I. Halpern. "An Investigation of PVT Effects on Geochemical Fingerprinting of Condensates From Gas Reservoirs." SPE Reservoir Evaluation & Engineering 12, no. 01 (2009): 88–95. http://dx.doi.org/10.2118/108441-pa.

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Summary One of the tools used for the characterization of gas reservoirs is the geochemistry of gas condensates. The fingerprinting of gas condensates by gas chromatography, in particular, may provide information regarding reservoir compartmentalization, which can be a major uncertainty at the early-field-appraisal stage. An important concern is the capture of suitable liquid samples. When the flowing bottomhole pressure falls below the dewpoint pressure, for example, condensate will drop out near the wellbore and the captured sample may not be representative of the formation fluid. We conduct

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Bei, Yu Bei, Li Hui, and Li Dong Lin. "The Researches on Reasonable Well Spacing of Gas Wells in Deep and low Permeability Gas Reservoirs." E3S Web of Conferences 38 (2018): 01038. http://dx.doi.org/10.1051/e3sconf/20183801038.

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This Gs64 gas reservoir is a condensate gas reservoir which is relatively integrated with low porosity and low permeability found in Dagang Oilfield in recent years. The condensate content is as high as 610g/m3. At present, there are few reports about the well spacing of similar gas reservoirs at home and abroad. Therefore, determining the reasonable well spacing of the gas reservoir is important for ensuring the optimal development effect and economic benefit of the gas field development. This paper discusses the reasonable well spacing of the deep and low permeability gas reservoir from the

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Bybee, Karen. "Well Productivity in Gas/Condensate Reservoirs." Journal of Petroleum Technology 52, no. 04 (2000): 67–68. http://dx.doi.org/10.2118/0400-0067-jpt.

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Raghavan, Rajagopal, and Jack R. Jones. "Depletion Performance of Gas-Condensate Reservoirs." Journal of Petroleum Technology 48, no. 08 (1996): 725–31. http://dx.doi.org/10.2118/36352-jpt.

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Singh, Kameshwar, and Curtis H. Whitson. "Gas-Condensate Pseudopressure in Layered Reservoirs." SPE Reservoir Evaluation & Engineering 13, no. 02 (2010): 203–13. http://dx.doi.org/10.2118/117930-pa.

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Vo, Dyung T., Jack R. Jones, and Rajagopal Raghavan. "Performance Predictions for Gas-Condensate Reservoirs." SPE Formation Evaluation 4, no. 04 (1989): 576–84. http://dx.doi.org/10.2118/16984-pa.

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Nowrouzi, Iman, Amir H. Mohammadi, and Abbas Khaksar Manshad. "Effect of a synthesized anionic fluorinated surfactant on wettability alteration for chemical treatment of near-wellbore zone in carbonate gas condensate reservoirs." Petroleum Science 17, no. 6 (2020): 1655–68. http://dx.doi.org/10.1007/s12182-020-00446-w.

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AbstractThe pressure drop during production in the near-wellbore zone of gas condensate reservoirs causes condensate formation in this area. Condensate blockage in this area causes an additional pressure drop that weakens the effective parameters of production, such as permeability. Reservoir rock wettability alteration to gas-wet through chemical treatment is one of the solutions to produce these condensates and eliminate condensate blockage in the area. In this study, an anionic fluorinated surfactant was synthesized and used for chemical treatment and carbonate rock wettability alteration.

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Ikpeka, Princewill M., Johnson O. Ugwu, Gobind G. Pillai, and Paul Russell. "Effect of direct current on gas condensate droplet immersed in brine solution." Journal of Petroleum Exploration and Production Technology 11, no. 6 (2021): 2845–60. http://dx.doi.org/10.1007/s13202-021-01184-4.

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AbstractEnvironmentally sustainable methods of extracting hydrocarbons from the reservoir are increasingly becoming an important area of research. Several methods are being applied to mitigate condensate banking effect which occurs in gas condensate reservoirs; some of which have significant impact on the environment (subsurface and surface). Electrokinetic enhanced oil recovery (EEOR) increases oil displacement efficiency in conventional oil reservoirs while retaining beneficial properties to the environment. To successfully apply this technology on gas condensate reservoirs, the behavior of

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Regueiro, José, and Andrés Peña. "AVO in North of Paria, Venezuela: Gas methane versus condensate reservoirs." GEOPHYSICS 61, no. 4 (1996): 937–46. http://dx.doi.org/10.1190/1.1444043.

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The gas fields of North of Paria, offshore eastern Venezuela, present a unique opportunity for amplitude variations with offset (AVO) characterization of reservoirs containing different fluids: gas‐condensate, gas (methane) and water (brine). AVO studies for two of the wells in the area, one with gas‐condensate and the other with gas (methane) saturated reservoirs, show interesting results. Water sands and a fluid contact (condensate‐water) are present in one of these wells, thus providing a control point on brine‐saturated properties. The reservoirs in the second well consist of sands highly

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Yong, Li, Zhang Jing, Wu Xueyong, Jiao Yuwei, and Yi Jie. "A new reservoir simulation approach for fractured gas-condensate reservoirs." Petroleum Exploration and Development 37, no. 5 (2010): 592–95. http://dx.doi.org/10.1016/s1876-3804(10)60056-0.

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Reis, Paula K. P., and Marcio S. Carvalho. "Pore-Scale Analysis of Condensate Blockage Mitigation by Wettability Alteration." Energies 13, no. 18 (2020): 4673. http://dx.doi.org/10.3390/en13184673.

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Liquid banking in the near wellbore region can lessen significantly the production from gas reservoirs. As reservoir rocks commonly consist of liquid-wet porous media, they are prone to liquid trapping following well liquid invasion and/or condensate dropout in gas-condensate systems. For this reason, wettability alteration from liquid to gas-wet has been investigated in the past two decades as a permanent gas flow enhancement solution. Numerous experiments suggest flow improvement for immiscible gas-liquid flow in wettability altered cores. However, due to experimental limitations, few studie

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Uzun, Ilkay, Basak Kurtoglu, and Hossein Kazemi. "Multiphase Rate-Transient Analysis in Unconventional Reservoirs: Theory and Application." SPE Reservoir Evaluation & Engineering 19, no. 04 (2016): 553–66. http://dx.doi.org/10.2118/171657-pa.

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Summary In unconventional reservoirs, production data are generally analyzed by use of rate-transient techniques derived from single-phase linear-flow models. Such linear-flow models use rate-normalized pressure, which is pressure drop divided by reservoir-flow rate vs. square root of time. In practice, the well-fluid production includes water, oil, and gas. The oil can be light oil, volatile oil, and gas/condensate as in the Bakken, Eagle Ford, and Barnett, respectively. Thus, single-phase analysis needs modification to account for production of fluid mixtures. In this paper, we present a mul

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Hou, Dali, Pingya Luo, Lei Sun, Yong Tang, and Yi Pan. "Study on Nonequilibrium Effect of Condensate Gas Reservoir with Gaseous Water under HT and HP Condition." Journal of Chemistry 2014 (2014): 1–8. http://dx.doi.org/10.1155/2014/295149.

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When a condensate gas reservoir with gaseous water under high temperature and high pressure condition is producing, the gaseous water and nonequilibrium effect will have great influences on the phase behavior of condensate oil and gas system and the accumulation of condensate liquid near the wellbore area. Therefore, a series of experiments were performed to investigate phase behavior of the condensate gas reservoirs with gaseous water using a PVT cell, in which the constant volume depletion process of nonequilibrium pressure drop and equilibrium pressure drop within near wellbore zone was sim

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Okotie, S., and N. O. Ogbarode. "EVALUATION OF AKPET GT9 GAS CONDENSATE RESERVOIR PERFORMANCE." Open Journal of Engineering Science (ISSN: 2734-2115) 1, no. 1 (2020): 1–13. http://dx.doi.org/10.52417/ojes.v1i1.80.

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To effectively evaluate a gas condensate reservoir performance, the reservoir engineer must have a reasonable amount of knowledge about the reservoir to adequately analyze the reservoir performance and predict future production under various modes of operation. Due to the multiphase flow that exists in the reservoir, characterization of gas condensate reservoirs is often a difficult task with the variation of its overall composition in both space and time during production which complicates well deliverability analysis and the sizing of surface facilities. This study is primarily concern with

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Mekmok, Karanthakarn, and Jirawat Chewaroungroaj. "Hydraulic Fracturing Designs For Low Permeability Gas Condensate Reservoirs Having Lean and Rich Condensate Compositions." International Journal of Research in Science 3, no. 3 (2017): 9. http://dx.doi.org/10.24178/ijrs.2017.3.3.09.

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Gas condensate reservoirs have been challenging many researchers in petroleum industry for decades because of their complexities in flow behavior. After dew point pressure is reached, gas condensate will drop liquid out and increase liquid saturation near wellbore vicinity called condensate banking or condensate blockage. Hydraulic fracturing in horizontal direction has been proved to be a reliable method to mitigate condensate blockage and increase productivity of gas condensate well by means of pressure redistribution in the near wellbore vicinity. In this paper the parameters of dimensionle

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Panikarovskii, E. V., V. V. Panikarovskii, A. B. Tulubaev, and D. N. Klepak. "Approaches to increasing well productivity in the development of the Bovanenkovo oil and gas condensate field." Oil and Gas Studies, no. 5 (November 17, 2019): 88–99. http://dx.doi.org/10.31660/0445-0108-2019-5-88-99.

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A large number of gas and gas condensate fields are located in the West Siberian mega-province and, to increase gas and gas condensate production levels, deposits located on the Yamal Peninsula should be introduced into development. Deposits of the Yamal Peninsula are complex-built deposits, Neocomian and Jurassic deposits have abnormally high reservoir pressure with a reservoir temperature of more than 100 ° C. The Bovanenkovo oil and gas condensate field is the largest in terms of gas reserves in the Yamal Peninsula; on this example, in this article we will study the issues of restoring the

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Pope, G. A., W. Wu, G. Narayanaswamy, M. Delshad, M. M. Sharma, and P. Wang. "Modeling Relative Permeability Effects in Gas-Condensate Reservoirs With a New Trapping Model." SPE Reservoir Evaluation & Engineering 3, no. 02 (2000): 171–78. http://dx.doi.org/10.2118/62497-pa.

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Summary Many gas-condensate wells show a significant decrease in productivity once the pressure falls below the dew point pressure. A widely accepted cause of this decrease in productivity index is the decrease in the gas relative permeability due to a buildup of condensate in the near wellbore region. Predictions of well inflow performance require accurate models for the gas relative permeability. Since these relative permeabilities depend on fluid composition and pressure as well as on condensate and water saturations, a model is essential for both interpretation of laboratory data and for p

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Bybee, Karen. "Well Test Analysis in Gas/Condensate Reservoirs." Journal of Petroleum Technology 52, no. 11 (2000): 68–70. http://dx.doi.org/10.2118/1100-0068-jpt.

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Labed, Ismail, Babs Oyeneyin, and Gbenga Oluyemi. "Gas-condensate flow modelling for shale reservoirs." Journal of Natural Gas Science and Engineering 59 (November 2018): 156–67. http://dx.doi.org/10.1016/j.jngse.2018.08.015.

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Matthews, J. D., R. I. Hawes, I. R. Hawkyard, and T. P. Fishlock. "Feasibility Studies of Waterflooding Gas-Condensate Reservoirs." Journal of Petroleum Technology 40, no. 08 (1988): 1049–56. http://dx.doi.org/10.2118/15875-pa.

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Al-Abri, Abdullah, and Robert Amin. "Numerical simulation of CO2 injection into fractured gas condensate reservoirs." APPEA Journal 51, no. 2 (2011): 742. http://dx.doi.org/10.1071/aj10122.

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More than sixty percent of the world’s remaining oil reserves are hosted by intensely fractured porous rocks, such as the carbonate sequences of Iran, Iraq, Oman, or offshore Mexico (Bedoun, 2002). The high contrast of capillarity between the matrix and the fractures makes a significant difference in the recovery performance of fractured and non-fractured reservoirs (Lemonnier and Bourbiaux, 2010). Simulation of naturally fractured reservoirs is a challenging task from both a reservoir description and a numerical standpoint (Selley, 1998). This paper presents the recovery performance of CO2 in

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Ganjdanesh, Reza, Mohsen Rezaveisi, Gary A. Pope, and Kamy Sepehrnoori. "Treatment of Condensate and Water Blocks in Hydraulic-Fractured Shale-Gas/Condensate Reservoirs." SPE Journal 21, no. 02 (2016): 665–74. http://dx.doi.org/10.2118/175145-pa.

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Summary The accumulation of condensate in fractures is one of the challenges of producing gas from gas/condensate reservoirs. When the bottomhole pressure drops to less than the dewpoint, condensate forms in and around fractures and causes a significant drop in the gas relative permeability, which leads to a decline in the gas-production rate. This reduction of gas productivity is in addition to the reduction because of water blocking by the fracturing water. Solvents can be used to remove liquid blocks and increase gas- and condensate-production rates. In this paper, dimethyl ether (DME) is i

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Kabir, C. Shah, and Julian J. Pop. "How Reliable Is Fluid Gradient in Gas/Condensate Reservoirs?" SPE Reservoir Evaluation & Engineering 10, no. 06 (2007): 644–56. http://dx.doi.org/10.2118/99386-pa.

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Summary Collection and analysis of gas/condensate-fluid samples presents considerable challenges. This is because downhole sampling of a gas/condensate fluid—unlike its oil counterpart—does not guarantee the retrieval of a single-phase fluid. The same is true for surface sampling because of incomplete surface and/or downhole separation. Given this reality, the pressure/volume/temperature (PVT) analysis of any fluid sample with an equation-of-state (EOS) model demands that the results are verified with independent measurements. Our analyses of many samples show that a good correspondence exists

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Fujisawa, Go, Maria A. Van Agthoven, Fredrick Jenet, Philip A. Rabbito, and Oliver C. Mullins. "Near-Infrared Compositional Analysis of Gas and Condensate Reservoir Fluids at Elevated Pressures and Temperatures." Applied Spectroscopy 56, no. 12 (2002): 1615–20. http://dx.doi.org/10.1366/000370202321116101.

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The near-infrared spectroscopic (NIR) analysis of several fluid mixtures approximating natural gases or condensates is reported. Spectra were measured under wide variations of pressure and temperature in accord with conditions found in various gas or condensate reservoirs. Some restrictions simulating currently feasible hardware specifications were placed on spectral data before they were used for analysis. We employed principal components regression (PCR) on inverted Beer's Law for compositional analysis. The result shows that it is feasible to conduct an in situ compositional analysis in the

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Farid, A. M. M., Ahmed H. El-Banbi, and A. A. A. Abdelwaly. "An Integrated Model for History Matching and Predicting Reservoir Performance of Gas/Condensate Wells." SPE Reservoir Evaluation & Engineering 16, no. 04 (2013): 412–22. http://dx.doi.org/10.2118/151869-pa.

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Summary The depletion performance of gas/condensate reservoirs is highly influenced by changes in fluid composition below the dewpoint. The long-term prediction of condensate/gas reservoir behavior is therefore difficult because of the complexity of both composition variation and two-phase-flow effects. In this paper, an integrated model was developed to simulate gas-condensate reservoir/well behavior. The model couples the compositional material balance or the generalized material-balance equations for reservoir behavior, the two-phase pseudo integral pressure for near-wellbore behavior, and

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Fahes, Mashhad Mousa, and Abbas Firoozabadi. "Wettability Alteration to Intermediate Gas-Wetting in Gas-Condensate Reservoirs at High Temperatures." SPE Journal 12, no. 04 (2007): 397–407. http://dx.doi.org/10.2118/96184-pa.

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Summary Wettability of two types of sandstone cores, Berea (permeability on the order of 600 md), and a reservoir rock (permeability on the order of 10 md), is altered from liquid-wetting to intermediate gas-wetting at a high temperature of 140C. Previous work on wettability alteration to intermediate gas-wetting has been limited to 90C. In this work, chemicals previously used at 90C for wettability alteration are found to be ineffective at 140C. New chemicals are used which alter wettability at high temperatures. The results show that:wettability could be permanently altered from liquid-wetti

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