Relevant bibliographies by topics / Gas condensate reservoir

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Academic literature on the topic 'Gas condensate reservoir'

Author: Grafiati
Published: 4 June 2021
Last updated: 3 February 2022

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Journal articles on the topic "Gas condensate reservoir"

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 (August 1, 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 can be somewhat restored by increasing production rate. High interfacial tension ultimately caused condensate relative permeability to decrease with increasing condensate saturation. Condensate immobile under gas injection could be recovered by water injection, but more immediate and efficient condensate recovery was observed when the condensate saturation prior to water injection exceeded the CCS. Subsequent blowdown recovered additional gas, but incremental condensate recovery was insignificant. Introduction Reservoirs bearing gas condensates are becoming more commonplace as developments are encountering greater depths, higher pressures, and higher temperatures. In the North Sea, gas condensate reservoirs comprise a significant portion of the total hydrocarbon reserves. Accuracy in engineering computations for gas condensate systems (e.g., estimating reserves, sizing surface facilities, and predicting productivity trends) depends upon a basic understanding of phase and flow behavior interrelationships. For example, gas productivity may be curtailed as condensate accumulates by pressure depletion below the dew point pressure (Pd). Conceptual modeling on gas condensate systems suggests that relative permeability (kr) curves govern the magnitude of gas productivity loss.1,2 Unfortunately, available gas and condensate relative permeability (krg and krc) results for gas condensates are primarily limited to synthetic systems. Such results show that higher CCS and less krg reduction were observed for a conventional gas/oil system compared to a gas condensate system.3,4 If condensate accumulates as a continuous film due to low interfacial tension (IFT), then high IFT gas/oil and water/oil kr data may not be applicable to gas condensates.5 Water invasion of gas condensate reservoirs may enhance hydrocarbon recovery or trap potential reserves. Laboratory results suggest water invasion of low IFT gas condensates may not be represented using high IFT water/oil and water/gas displacements.6 Subsequent blowdown may remobilize hydrocarbons trapped by water invasion. The presence of condensate may hinder gas remobilization, thus conventional gas/water blowdown experiments may not be appropriate in evaluating the feasibility of depressurization for gas condensates.7,8 Other laboratory evaluations of gas condensate flow behavior indicate measured results depend upon experimental procedures, fluid properties, and rock properties.3,9–20 Factors to consider include the history of condensate formation (i.e., imbibition or drainage), how condensate was introduced (i.e., in-situ dropout versus external injection or inflowing gas), flow rate, differential pressure, system pressure, IFT, connate water saturation, core permeability, and core orientation. Experiments performed to evaluate the consequences of water invasion suggest optimum conditions depend upon IFT, initial gas saturation, and core permeability.7,21,22 Reported blowdown experiments imply gas recovery depends upon the degree of gas expansion.7,8 The kr results obtained in this study represent gas condensate flow between the far-field and the near-wellbore region. The results are useful input for numerical simulation, especially to test rate- or IFT-sensitive relative permeability functions. Results on hydrocarbon recovery and trapping from water injection and blowdown are beneficial in evaluating improved recovery options for gas condensates. Experimental Procedures Coreflooding experiments were performed under reservoir conditions using rock and fluid samples from two distinct North Sea gas condensate reservoirs. A detailed description of the experimental methods is provided in the Appendix. Briefly, the experiments were conducted in a horizontal coreflood apparatus equipped with in-line PVT and viscosity measuring devices. The entire system experienced in-situ condensate drop out by constant volume depletion (CVD) from above Pd to either the pressure corresponding to CCS, or to the pressure of maximum condensate saturation Scmax Steady-state krg was measured by injecting equilibrated gas (before CCS). Steady-state krg and krc were measured by injecting gas condensate repressurized to above Pd (after CCS). The gas/oil fractional flow rate was defined by the pressure level in the core which was controlled by the core outlet back-pressure regulator. During krg measurements, the injection rate was varied to access rate effects. After the krg or krg and krc measurements to Scmax were completed, water injection was performed to quantify hydrocarbon trapping and recovery. Blowdown followed to evaluate additional hydrocarbon recovery. Recombined Reservoir Fluid Properties. Two North Sea gas condensate reservoir fluids were recombined using separator oil and synthetic gas. Tables 1 and 2 list compositions and PVT properties for the reconstituted fluids. The Pd was 7,070 psig at 250°F for Reservoir A, and 6,074 psig at 259°F for Reservoir B (Table 2). The maximum liquid dropout under constant composition expansion (CCE) was 31.7% for Reservoir A, and 42.5% for Reservoir B (Fig. 1). Reservoir B is a richer gas condensate and exhibits more near-critical phase behavior than Reservoir A.
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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, the pressure and the condensate blocking will extend to further reservoir, while the pressure and condensate just appear in the vicinity of wellbore in low permeability gas condensate reservoirs. Second, the influence of pressure drop on condensate distribution in high permeability gas condensate reservoirs is obvious, the condensate blocking extends with the increasing of the pressure drop, and condensate extent can be controlled by optimizing a rational pressure drop, while the influence is inconspicuous in low permeability gas condensate reservoirs. Third, the influence of pressure drop on condensate oil production in high / moderate permeability gas condensate reservoirs is conspicuous, a rational pressure drop exists, while the influence is indistinct in low permeability or tight gas condensate reservoirs, before the retrograde condensation, a low pressure drop should be adopted in a long term until the bottom hole flowing pressure drops below the dew point pressure, when the condensate blocking forms, well stimulation is advised before developing by pressure control.
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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 (December 31, 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 functionally dependent on the nine main factors that most affect condensate recovery in ultralow-permeability reservoirs. The models were developed by regressing the results of experimentally designed compositional simulations. The Box-Behnken (Box and Behnken 1960) technique, a partial-factorial method, was used for design of these experiments or simulations. The main factors that controlled condensate recovery from ultralow-permeability reservoirs were reservoir permeability, rock compressibility, initial condensate/gas ratio (CGR), initial reservoir pressure, and fracture spacing. Another main outcome of this paper was the generation of probability-density functions, and P10, P50, and P90 values for condensate recovery on the basis of the uncertainty in input parameters. The condensate-recovery P50 for rate-based outcome of a 5-B/D per fracture was found to be less than 10%.
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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 (August 3, 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 accumulation-condensate blockage courtesy of high molecular weight, heavy condensate residue. Recovering lost condensate most economically and optimally has always been a challenging goal. Thus, gas cycling is applied to alleviate such a drastic loss in resources.In gas injection, the flooding pattern, injection timing and injection duration are key parameters to study an efficient EOR scenario in order to recover lost condensate. This work contains sensitivity analysis on different parameters to generate an accurate investigation about the effects on performance of different injection scenarios in homogeneous gas condensate system. In this paper, starting time of gas cycling and injection period are the parameters used to influence condensate recovery of a five-spot well pattern which has an injection pressure constraint of 3000 psi and production wells are constraint at 500 psi min. BHP. Starting injection times of 1 month, 4 months and 9 months after natural depletion areapplied in the first study. The second study is conducted by varying injection duration. Three durations are selected: 100 days, 400 days and 900 days.In miscible gas injection, miscibility and vaporization of condensate by injected gas is more efficient mechanism for condensate recovery. From this study, it is proven that the application of gas cycling on five-spot well pattern greatly enhances condensate recovery preventing financial, economic and resource loss that previously occurred.
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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-critical gas condensate reservoir fluid. In addition to the experimental studies, a commercial simulator combined with the PREOS model was utilized to study retrograde condensate characteristics and reevaporation mechanism of condensate oil with CO2injection based on vapor-liquid phase equilibrium thermodynamic theory. The research shows that when reservoir pressure drops below a certain pressure, the variation of retrograde condensate liquid saturation of the residual reservoir fluid exhibits the phase behavior of volatile oil.
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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 (April 12, 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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Thomas, F. B., D. B. Bennion, and G. Andersen. "Gas Condensate Reservoir Performance." Journal of Canadian Petroleum Technology 48, no. 07 (July 1, 2009): 18–24. http://dx.doi.org/10.2118/09-07-18.

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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 (December 1, 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 empirical correlations which can be used in reservoir simulators. Introduction Well deliverability is an important issue in the development of many gas-condensate reservoirs, especially where permeability is low. When the well bottomhole flowing pressure falls below the dewpoint, condensate liquid may build up around the wellbore, causing a reduction in gas permeability and well productivity. In extreme cases the liquid saturation may reach values as high as 50 or 60% and the well deliverability may be reduced by up to an order of magnitude. The loss in productivity due to this "condensate banking" effect may be significant, even in very lean gas-condensate reservoirs. For example, in the Arun reservoir,1 the productivity reduced by a factor of about 2 as the pressure fell below the dewpoint, even though the reservoir fluid was very lean with a maximum liquid drop out of only 1% away from the well. Most of the pressure drop from condensate blockage occurs within a few feet of the wellbore, where velocities are very high. There is a growing body of evidence from laboratory coreflood experiments to suggest that gas-condensate relative permeabilities increase at high velocities, and that these changes can be correlated against the capillary number.2–8 The capillary number is a dimensionless number that measures the relative strength of viscous and capillary forces. There are several gas-condensate fields where simulation with conventional relative permeability models has been found to underestimate well productivity.1,9,10 To obtain a good match between simulation results and well-test data, it was necessary to increase the mobility in the near-well region, either empirically or through a model of the increase in relative permeability at high velocity. This effect can increase well productivity significantly, and in some cases may eliminate most of the effect of condensate blockage. Experimental Data Requirements Fevang and Whitson11 have shown that the key parameter in determining well deliverability is the relationship between krg and the ratio krg/ kro. When high-velocity effects are significant, the most important information is the variation of krg with krg/k ro and the capillary number Nc. The relevant values of krg/kro are determined by the pressure/volume/temperature (PVT) properties of the reservoir fluids, but typical values might be 10 to 100 for lean condensates, 1 to 10 for rich condensates, and 0.1 to 10 for near-critical fluids. There are various ways of defining the capillary number, but in this paper we use the definition (1)Nc=vgμgσ, so that the capillary number is proportional to the gas velocity and inversely proportional to interfacial tension (IFT). The capillary numbers that are relevant for well deliverability depend on the flow rate, fluid type, and well bottomhole pressure, but as a general rule, values between 10?6 and 10?3 are most important. Experimental Methods In a gas-condensate reservoir, there are important differences between the flow regimes in the regions close to and far from the well. These different flow regimes are reflected in the requirements for relative permeability data for the deep reservoir and near-well regions. Far from the well, velocities are low, and liquid mobility is usually less important, except in reservoirs containing very rich fluids. In the near-well region, both liquid and gas phases are mobile, velocities are high, and the liquid mobility is important because of its effect on the relationship between krg and krg/kro. Depletion Method. Relative permeabilities for the deep reservoir region are often measured in a coreflood experiment, where the fluids in the core are obtained by a constant volume depletion (CVD) on a reservoir fluid sample. Relative permeabilities are measured at decreasing pressures from the fluid dewpoint, and increasing liquid saturation. In this type of experiment, the liquid saturation cannot exceed the critical condensate saturation or the maximum value in a CVD experiment, so that it is not possible to acquire data at the high liquid saturations that occur in the reservoir near to the well. The "depletion" experiment provides relative permeability data that are relevant to the deep reservoir, but there can be problems in interpreting the results due to the effects of IFT. Changes in liquid saturation are achieved by reducing pressure, which results in a change of IFT. The increase in IFT as pressure falls may cause a large reduction in mobility, and Chen et al.12 describe an example where the condensate liquid relative permeability decreases with increasing liquid saturation. Steady-State Method. The steady-state technique can be used to measure relative permeabilities at the higher liquid saturations that occur in the near-well region. Liquid and gas can be injected into the core from separate vessels, allowing relative permeabilities to be measured for a wide range of saturations. Results of gas-condensate relative permeabilities measured by this technique have been reported by Henderson et al.2,6 and Chen et al.12 .
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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 (December 11, 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, condensate build-up; and Region 3, single-phase gas) associated with single and two-phase gas and immobile and mobile gas condensate. The results show that permeability has a significant influence on the occurrence of the three regions around the well, which in turn affects the productivity of the gas condensate reservoir studied. Predictions of the timing and location of condensate in reservoirs with different permeability levels of 1 mD to 100 mD indicate that local damage enhances condensate formation by 60% and shortens the duration of the immobile phase by 45%. Meanwhile, the global change in permeability increases condensate formation by 80% and reduces the presence of the immobile phase by 60%. Finally, this predictive approach can help in mitigating condensate blockage around the wellbore during production.
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Rahimzadeh, Alireza, Mohammad Bazargan, Rouhollah Darvishi, and Amir H. Mohammadi. "Condensate blockage study in gas condensate reservoir." Journal of Natural Gas Science and Engineering 33 (July 2016): 634–43. http://dx.doi.org/10.1016/j.jngse.2016.05.048.

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Dissertations / Theses on the topic "Gas condensate reservoir"

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Al-Kharusi, Badr Soud. "Relative permeability of gas-condensate near wellbore, and gas-condensate-water in bulk of reservoir." Thesis, Heriot-Watt University, 2000. http://hdl.handle.net/10399/1098.

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Shaidi, Salman Mohammed Al. "Modelling of gas-condensate flow in reservoir at near wellbore conditions." Thesis, Heriot-Watt University, 1997. http://hdl.handle.net/10399/672.

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The behaviour of gas condensate flow in the porous media is distinctly different from that of gas-oil flow. The differences are attributed to the difference in fluid properties, phase behaviour, and condensation and vaporisation phenomena that distinguishes gas condensate fluids from the aforementioned fluid types. These differences manifest themselves into an important flow parameter that is typically known as relative permeability. Relative permeability is known to be related to the phase saturation, and the interfacial tension (EFT). Also, at high phase velocities, its reduction with increasing velocity, known as Forchheimer (turbulence) or inertia effect, is well documented. An unconventional behaviour of gas condensate fluids has been experimentally proven in Heriot-Watt laboratory and confirmed by other experimental studies performed elsewhere. These tests have shown that at intermediate velocities, before the inertia becomes significant, the gas and the condensate relative permeabilities are significantly improved by increase in velocity. This phenomenon is referred to as the rate-effect. None of the conventional relative permeability models include this experimentally proven favourable rate effect. In this work the flow of gas condensate fluids in porous media is modelled with emphasis on near wellbore conditions. Theoretical, empirical as well as simulational investigations are used to improve the present technology on the treatment of the flow of gas condensate in reservoirs. The use of X-ray or y-ray devices to monitor saturation profile during displacement experiments is investigated and the appropriate test conditions leading to reliable measured relative permeability data are determined. The regimes of the gas condensate flow at the core level, where the rate effect is evident, are investigated using the concept of Reynolds number. Then a mechanistic flow model, where the flow of gas condensate fluids is assumed to follow an annularmist flow criterion, is presented to capture the essence of the rate effect in perforations. The favourable EFT and rate effects are incorporated into the modelling of gas condensate relative permeability by correlating it with capillary number (I\Ic). Two forms of the correlation are presented. The impact of EFT and Ne together with the Forchheimer (inertia) on well deliverability is thoroughly investigated using the above correlation. The gas condensate relative permeability correlation is combined with the Forchheimer effect and used in a specially modified version of a commercial simulator, Eclipse 300V 98a development, to investigate the impact of IFT, Nc, and inertia on well productivity. The impact is found to accelerate production from gas condensate reservoirs. At practical production rates, the significance of the impact on phase recoveries cannot be ignored regardless of reservoir fluid richness or absolute permeability.
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Mindek, Cem. "Production Optimization Of A Gas Condensate Reservoir Using A Black Oil Simulator And Nodal System Analysis:a Case Study." Master's thesis, METU, 2005. http://etd.lib.metu.edu.tr/upload/12606112/index.pdf.

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In a natural gas field, determining the life of the field and deciding the best production technique, meeting the economical considerations is the most important criterion. In this study, a field in Thrace Basin was chosen. Available reservoir data was compiled to figure out the characteristics of the field. The data, then, formatted to be used in the commercial simulator, IMEX, a subprogram of CMG (Computer Modeling Group). The data derived from the reservoir data, used to perform a history match between the field production data and the results of the simulator for a 3 year period between May 2002 and January 2005. After obtaining satisfactory history matching, it was used as a base for future scenarios. Four new scenarios were designed and run to predict future production of the field. Two new wells were defined for the scenarios after determining the best region in history matching. Scenario 1 continues production with existing wells, Scenario 2 includes a new well called W6, Scenario 3 includes another new well, W7 and Scenario 4 includes both new defined wells, W6 and W7. All the scenarios were allowed to continue until 2010 unless the wellhead pressure drops to 500 psi. None of the existing wells reached 2010 but newly defined wells achieved to be on production in 2010. After comparing all scenarios, Scenario 4, production with two new defined wells, W6 and W7, was found to give best performance until 2010. During the scenario 4, between January 2005 and January 2010, 7,632 MMscf gas was produced. The total gas production is 372 MMscf more than Scenario 2, the second best scenario which has a total production of 7,311MMscf. Scenario 3 had 7,260 MMscf and Scenario 1 had 6,821 MMscf respectively. A nodal system analysis is performed in order to see whether the initial flow rates of the wells are close to the optimum flow rates of the wells, Well 1 is found to have 6.9 MMscf/d optimum production rate. W2 has 3.2 MMscf/d, W3 has 8.3 MMscf/d, W4 has 4.8 MMscf/d and W5 has 0.95 MMscf/d optimum production rates respectively.
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Delicado, Victor Edward. "A comparison of black-oil versus compositional simulation methods for evaluating a rich gas-condensate reservoir." University of the Western Cape, 2016. http://hdl.handle.net/11394/5860.

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Magister Scientiae - MSc
Over time, researchers have endeavoured to use conventional black-oil (BO) models to model volatile-oil and gas-condensate reservoirs as accurately as possible, with variable levels of success. The black-oil approach allows for the implementation of a simpler and less expensive computational algorithm than that associated with a compositional model. The first-mentioned can result in substantial time-saving in full field studies. This project evaluates the use of modified black-oil (MBO) as well as compositional (equation of state- EOS) approaches to determine the expected recovery and performance of a rich gascondensate reservoir. After initialization, the models reflected very similar in-place hydrocarbon volumes, with a deviation percentage of less than 5 % between the two modelling approaches.
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Ouzzane, Djamel Eddine. "Phase behaviour in gas condensate reservoirs." Thesis, Imperial College London, 2005. http://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.417922.

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Labed, Ismail. "Gas-condensate flow modelling for shale gas reservoirs." Thesis, Robert Gordon University, 2016. http://hdl.handle.net/10059/2144.

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In the last decade, shale reservoirs emerged as one of the fast growing hydrocarbon resources in the world unlocking vast reserves and reshaping the landscape of the oil and gas global market. Gas-condensate reservoirs represent an important part of these resources. The key feature of these reservoirs is the condensate banking which reduces significantly the well deliverability when the condensate forms in the reservoir below the dew point pressure. Although the condensate banking is a well-known problem in conventional reservoirs, the very low permeability of shale matrix and unavailability of proven pressure maintenance techniques make it more challenging in shale reservoirs. The nanoscale range of the pore size in the shale matrix affects the gas flow which deviates from laminar Darcy flow to Knudsen flow resulting in enhanced gas permeability. Furthermore, the phase behaviour of gas-condensate fluids is affected by the high capillary pressure in the matrix causing higher condensate saturation than in bulk conditions. A good understanding and an accurate evaluation of how the condensate builds up in the reservoir and how it affects the gas flow is very important to manage successfully the development of these high-cost hydrocarbon resources. This work investigates the gas Knudsen flow under condensate saturation effect and phase behaviour deviation under capillary pressure of gas-condensate fluids in shale matrix with pore size distribution; and evaluates their effect on well productivity. Supplementary MATLAB codes are provided elsewhere on OpenAIR: http://hdl.handle.net/10059/2145.
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Vo, Dyung Tien. "Well test analysis for gas condensate reservoirs /." Access abstract and link to full text, 1989. http://0-wwwlib.umi.com.library.utulsa.edu/dissertations/fullcit/9014121.

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Al, Harrasi Mahmood Abdul Wahid Sulaiman. "Fluid flow properties of tight gas-condensate reservoirs." Thesis, University of Leeds, 2011. http://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.582106.

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Tight gas-condensate reservoirs contain large reserves, but can be extremely costly to develop. Understanding the fundamental controls on the fluid flow behaviour of tight gas and gas-condensate reservoirs has the potential to result in more cost-effective reservoir development and help increase the world's producible reserves. Therefore, the principal objective of the thesis is to improve understanding of multiphase flow within tight gas-condensate reservoirs. In order to achieve this objective a series of pore-to-core scale experiments under controlled conditions were performed, followed by numerical simulation. Three methodologies were used in this study: First, pore-scale experiments in glass micromodels with liquid-liquid systems were performed to improve understanding of the phase separation and flow mechanisms at pore level. Second, coreflood experiments were performed while in-situ saturation was monitored using an X-ray C'I' -scanner. A newly developed liquid-liquid system was used in these experiments. Flow through tight gas sandstones allowed the determination of relative penneabilities as well as determining their dependence on absolute permeability and capillary number. Third, production simulation modelling has been conducted to investigate the implications of the results. The micromodel experiments have proved extremely useful for characterizing the flow behaviour . of condensate systems. The results showed that the flow mechanisms and phases' distributions were affected largely by interfacial tension, pore structure and wettability.
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Del, Castillo Maravi Yanil. "New inflow performance relationships for gas condensate reservoirs." Texas A&M University, 2003. http://hdl.handle.net/1969/354.

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Aluko, Olalekan A. "Well test dynamics of rich gas condensate reservoirs." Thesis, Imperial College London, 2011. http://hdl.handle.net/10044/1/7887.

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Books on the topic "Gas condensate reservoir"

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Kushnirov, V. V. Retrogradnye gazozhidkostnye sistemy v nedrakh. Tashkent: Izd-vo "Fan" Uzbekskoĭ SSR, 1987.

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Zibert, G. K. Perspektivnye tekhnologii i oborudovanie dli︠a︡ podgotovki i perepodgotovki uglevodorodnykh gazov i kondensata: Prospective Tecnologies and Equipment for Preparation and Processing Hydrocarbon Gases and Condensate. Moskva: Nedra, 2005.

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Ė, Ramazanova Ė. Prikladnai͡a︡ termodinamika neftegazokondensatnykh mestorozhdeniĭ. Moskva: "Nedra", 1986.

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Dolgushin, N. V. Terminologii︠a︡ i osnovnye polozhenii︠a︡ tekhnologii gazokondensatnykh issledovaniĭ = Terminology and basic principles of technique for gas condensate research. Moskva: Nedra, 2004.

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Serebri︠a︡kov, A. O. Sinergetika razvedki i razrabotki nefti︠a︡nykh i gazovykh mestorozhdeniĭ-gigantov s kislymi komponentami: Monografii︠a︡. Astrakhanʹ: Astrakhanskiĭ gos. universitet, 2006.

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Krylov, G. V., and I︠U︡ K. Vasilʹchuk. Kriosfera neftegazokondensatnykh mestorozhdeniĭ poluostrova I︠A︡mal: Cryosphere of oil and gas condensate fields of Yamal Peninsula. Ti︠u︡menʹ: Ti︠u︡menNIIgiprogaz, 2006.

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Gasumov, R. A. Geologii︠a︡, burenie i razrabotka gazovykh i gazokondensatnykh mestorozhdeniĭ. Stavropolʹ: SevKavNIPIgaz, 2008.

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P, Zaporozhet︠s︡ E., and Valiullin I. M, eds. Podgotovka i pererabotka uglevodorodnykh gazov i kondensata: Tekhnologii i oborudovanie, spravochnoe posobie. 2nd ed. Moskva: Nedra, 2008.

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9

Vysot͡skiĭ, I. V. Formirovanie nefti͡anykh, gazovykh i kondensatnogazovykh mestorozhdeniĭ. Moskva: "Nedra", 1986.

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I͡Azik, A. V. Sistemy i sredstva okhlazhdenii͡a prirodnogo gaza. Moskva: "Nedra", 1986.

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Book chapters on the topic "Gas condensate reservoir"

1

Zhang, An-gang, Zi-fei Fan, Lun Zhao, Cong-ge He, and Jin-cai Wang. "Study on Development Policy of Maintaining Reservoir Pressure in Condensate Gas Reservoir." In Springer Series in Geomechanics and Geoengineering, 1632–39. Singapore: Springer Singapore, 2020. http://dx.doi.org/10.1007/978-981-15-2485-1_147.

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Liang, Bin, Xian-Hong Tan, Guo-Jin Zhu, Bo Tian, Shuai Wang, Nan Li, and Xiang Fan. "Study on Improving Recovery of Condensate Oil in Low Perm and High Condensate Gas Reservoir." In Springer Series in Geomechanics and Geoengineering, 3123–32. Singapore: Springer Singapore, 2021. http://dx.doi.org/10.1007/978-981-16-0761-5_293.

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Wang, Li-wei, Xiu-ling Han, Min Jia, Su-zhen Li, and Ying Gao. "Study on Potential Exploitation by Restimulation of Deep Tight Gas Condensate Reservoir." In Springer Series in Geomechanics and Geoengineering, 2689–98. Singapore: Springer Singapore, 2021. http://dx.doi.org/10.1007/978-981-16-0761-5_251.

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Li, Su-zhen, Xue-fang Yuan, Yu-jin Wan, Liao Wang, Guo-wei Xu, and Wen-tong Fan. "Experimental Investigation of Formation Damage Induced by Completion in Dibei Tight Condensate Gas Reservoir." In Springer Series in Geomechanics and Geoengineering, 533–43. Singapore: Springer Singapore, 2021. http://dx.doi.org/10.1007/978-981-16-0761-5_52.

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Jreou, Ghazwan Noori Saad. "Determination of Deliverability Equation and IPR for Siba Gas Condensate Reservoir in (Iraq)—Case Study." In Advances in Petroleum Engineering and Petroleum Geochemistry, 185–88. Cham: Springer International Publishing, 2019. http://dx.doi.org/10.1007/978-3-030-01578-7_43.

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Ding, Wei, Yun-peng Hu, Xiao-ling Zhang, and Xiao-yan Liu. "A Study on CO2 Enhanced Oil Rim Recovery for Complex Fault Block Sandstone Gas Condensate Reservoir." In Springer Series in Geomechanics and Geoengineering, 3117–26. Singapore: Springer Singapore, 2020. http://dx.doi.org/10.1007/978-981-15-2485-1_288.

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Zhang, Xiaoling, Wei Ding, Yunpeng Hu, and Xiaoyan Liu. "Research and Application of the Evaluation System for a Complex Fault Block Sandstone Condensate Gas Reservoir." In Proceedings of the International Field Exploration and Development Conference 2018, 865–72. Singapore: Springer Singapore, 2019. http://dx.doi.org/10.1007/978-981-13-7127-1_80.

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Al-Ramadan, Khalid, Sadoon Morad, A. Kent Norton, and Michael Hulver. "Linking Diagenesis and Porosity Preservation Versus Destruction to Sequence Stratigraphy of Gas Condensate Reservoir Sandstones; The Jauf Formation (Lower to Middle Devonian), Eastern Saudi Arabia." In Linking Diagenesis to Sequence Stratigraphy, 297–335. West Sussex, UK: John Wiley & Sons, Inc., 2013. http://dx.doi.org/10.1002/9781118485347.ch13.

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Reffstrup, Jan, and Henrik Olsen. "Evaluation of PVT Data from Low Permeability Gas Condensate Reservoirs." In North Sea Oil and Gas Reservoirs — III, 289–96. Dordrecht: Springer Netherlands, 1994. http://dx.doi.org/10.1007/978-94-011-0896-6_25.

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"Gas-Condensate Reservoirs." In Rules of Thumb for Petroleum Engineers, 365–66. Hoboken, NJ, USA: John Wiley & Sons, Inc., 2017. http://dx.doi.org/10.1002/9781119403647.ch165.

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Conference papers on the topic "Gas condensate reservoir"

1

Izuwa, Nkemakolam Chinedu, Boniface Obah, and Dulu Appah. "Optimal Gas Production Design in Gas Condensate Reservoir." In SPE Nigeria Annual International Conference and Exhibition. Society of Petroleum Engineers, 2014. http://dx.doi.org/10.2118/172453-ms.

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Panfilova, I., and M. Panfilov. "Representation of Gas-Condensate Wells in Numerical Reservoir Simulations." In SPE Reservoir Simulation Symposium. Society of Petroleum Engineers, 1997. http://dx.doi.org/10.2118/38022-ms.

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Fuad, Iqmal Irsyad Mohammad, Jang Hyun Lee, Nur Asyraf Md Akhir, and Izzati Zulkifli. "Enumeration Approach in Condensate Banking Study of Gas Condensate Reservoir." In Abu Dhabi International Petroleum Exhibition & Conference. Society of Petroleum Engineers, 2017. http://dx.doi.org/10.2118/188589-ms.

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Shams*, Bilal, Jun Yao, Kai Zhang, and Lei Zhang. "Sensitivity Studies for Enhancing Condensate Recovery of Gas Condensate Reservoir." In International Geophysical Conference, Qingdao, China, 17-20 April 2017. Society of Exploration Geophysicists and Chinese Petroleum Society, 2017. http://dx.doi.org/10.1190/igc2017-291.

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Udosen, Emmanuel O., Okpanachi O. Ahiaba, and Samuel B. Aderemi. "Optimization of Gas Condensate Reservoir Using Compositional Reservoir Simulator." In Nigeria Annual International Conference and Exhibition. Society of Petroleum Engineers, 2010. http://dx.doi.org/10.2118/136964-ms.

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Odi, Uchenna, and Anuj Gupta. "Fractional Flow Analysis of Displacement in a CO2 Enhanced Gas Recovery Process for Carbonate Reservoirs." In ASME 2012 31st International Conference on Ocean, Offshore and Arctic Engineering. American Society of Mechanical Engineers, 2012. http://dx.doi.org/10.1115/omae2012-84173.

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Abstract:
This paper presents fractional flow analysis of displacement of gas/condensate in a wet/condensate gas reservoir by CO2 that includes interactions between CO2 and condensate. Phase behavior affects the performance of carbon dioxide enhanced oil/ gas recovery processes in a significant manner. It also controls the effectiveness of carbon dioxide sequestration processes. In the past, there has been a focus on understanding interactions of CO2 with matrix and other fluids in oil reservoirs by various researchers. However, there is now an increasing interest in understanding carbon dioxide interactions in gas condensate reservoirs so that CO2 can be used to increase recovery. For a carbonate reservoir containing gas-condensates, this new focus requires a fundamental understanding of the interactions of carbon dioxide with condensate and gas phases. This paper describes the relative effect that these mechanisms have by conducting a fractional flow analysis for Enhanced Gas Recovery. These mechanisms include miscibility and partitioning of CO2 in various phases. Understanding these mechanisms is essential to modeling Enhanced Oil/Gas Recovery using CO2. The analysis honors the material balance and accounts for miscibility between carbon dioxide and condensate. The results of the fractional flow analysis are important for validation of computer simulation of the comparable processes. This work is expected to serve as a foundation work in understanding the mechanisms involved in CO2 assisted enhanced oil and gas recovery.
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O'Bryne, D. K., S. Sadighi, and G. L. Lane. "Simulation of the North Brae Gas Condensate Reservoir Development." In SPE Symposium on Reservoir Simulation. Society of Petroleum Engineers, 1991. http://dx.doi.org/10.2118/21245-ms.

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Bertram, D. A., L. E. C. van de Leemput, B. S. McDevitt, and N. M. A. Al Harthy. "Experiences in Gas-condensate Well Test Analysis Using Compositional Simulation." In SPE Reservoir Simulation Symposium. Society of Petroleum Engineers, 1997. http://dx.doi.org/10.2118/37994-ms.

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Seto, C. J., K. Jessen, and F. M. Orr. "Compositional Streamline Simulation of Field Scale Condensate Vaporization by Gas Injection." In SPE Reservoir Simulation Symposium. Society of Petroleum Engineers, 2003. http://dx.doi.org/10.2118/79690-ms.

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Kriel, W. A., A. P. Spence, E. J. Kolodziej, and S. P. Hoolahan. "Improved Gas Chromatographic Analysis of Reservoir Gas and Condensate Samples." In SPE International Symposium on Oilfield Chemistry. Society of Petroleum Engineers, 1993. http://dx.doi.org/10.2118/25190-ms.

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Reports on the topic "Gas condensate reservoir"

1

Sheng, James, Lei Li, Yang Yu, Xingbang Meng, Sharanya Sharma, Siyuan Huang, Ziqi Shen, et al. Maximize Liquid Oil Production from Shale Oil and Gas Condensate Reservoirs by Cyclic Gas Injection. Office of Scientific and Technical Information (OSTI), November 2017. http://dx.doi.org/10.2172/1427584.

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