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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 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 (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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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 shale reservoirs. Experimentally, CO2 huff-n-puff tests on shale core were conducted. A theoretical field scale simulation model was constructed. The effects of injection pressure, injection time, and soaking time on the efficiency of CO2 huff-n-puff were examined. Experimental results indicate that condensate recovery was enhanced to 30.36% after 5 cycles of CO2 huff-n-puff. In addition, simulation results indicate that the injection period and injection pressure should be optimized to ensure that the pressure of the main condensate region remains higher than the dew point pressure. The soaking process should be determined based on the injection pressure. This work may shed light on a better understanding of the CO2 huff-n-puff- enhanced oil recovery (EOR) strategy in shale gas condensate reservoirs.
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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 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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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, 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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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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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 complex fluid behavior nature of gas-condensate fluids, a fully-implicit (IMPISC-type) compositional model is implemented and the model is used for the study of the isothermal depletion of naturally fractured retrograde gas reservoirs. In these systems, especially those tight systems with very low permeability (k < 0.1 md), bulk fluid flow as predicted by Darcy's law might not take place despite the presence of large pressure gradients. The use of an effective diffusion coefficient in the gas phase—which accounts for the combined effect of the different diffusion mechanisms that could take place in a porous medium—and its relative contribution to fluid recovery is discussed. The compositional tracking capabilities of the model are tested, and the conditions where Fickian flow can be the major player in recovery predictions and considerably overcome the flow impairment to gas flow posed by the eventual appearance of a condensate barrier—typical of gas-condensate systems—are investigated. Finally, a mapping that defines different domains where multimechanistic flow can be expected in compositional simulators of retrograde gas-condensate reservoirs is presented. Introduction In typical natural-gas reservoirs, all hydrocarbons exist as a single free gas phase at conditions of discovery. Depending on the composition of the initial hydrocarbon mixture in place and their depletion behavior, we recognize up to three kinds of natural gas reservoirs: dry gas reservoirs, wet gas reservoirs, and retrograde gas or gas-condensate reservoirs. The latter is the richest in terms of heavy hydrocarbons, and thus it is very likely to develop a second heavier hydrocarbon phase (liquid condensate) upon isothermal depletion. This situation is illustrated by Fig. 1. In contrast, dry gases and wet gases do not undergo phase changes upon reservoir depletion, as their phase envelope's cricondentherms are found to the left of the reservoir temperature isotherm.
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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 (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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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 side to smaller pores that, under favorable conditions, can lead to larger economic benefits from organic-rich shale reservoirs. This occurs in the case of condensate fluids that behave as dry gas in the smaller pores of organic-rich shale reservoirs. Flow of this dry gas diminishes the amount of liquids that are released and lost permanently in a shale reservoir. Conversely, this dry gas can lead to larger recovery of liquids in the surface from a given shale reservoir and consequently more attractive economics. This study shows how the smaller pores and their associated dry gas can be recognized with the use of process speed (flow units) and modified Pickett plots. Data from the Niobrara and Eagle Ford shales are used to demonstrate these crossplots. It is concluded that there is significant practical potential in the use of process speed as part of the flow-unit characterization of shale condensate reservoirs. This, in turn, can help in locating sweet spots for improved liquid production. The main contribution of this work is the association of flow units and different scales of pore apertures for improving recovery of liquids from shale reservoirs.
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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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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 ring, the gas cap continue to spread to the oil region, while there are a large number of condensate oil anti-condensate from the gas cap, which loss into the formation. In this paper, the authors consider the characteristics of the oil and gas reservoirs and research the technique policy of collaborative development, These are all in order to solve technical problems, which is keep the pressure balance between the gas cap and oil ring during collaborative development. Not only provide technical to support the rational and efficient development of the Г North oil and gas reservoirs, but also provide a stable source for natural gas pipeline from Kazakhstan to China.
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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 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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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 seepage model. Based on the ellipsoidal horizontal well seepage model, considering the advance of edge water to the bottom of the well and condensate oil to formation, the advance of edge water is divided into two processes. The time when the first water molecule reaches the bottom of the well when the edge water tongue enters is deduced, that is, the time of edge water breakthrough in condensate gas reservoir.The calculation results show that the relative error of water breakthrough time considering retrograde condensate pollution is less than that without consideration, with a higher accuracy. The example error is less than 2%, which can be effectively applied to the development of edge water gas reservoir.
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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 repeatability of the data. A relative permeability rate effect for both gas and condensate phases was observed, with the relative permeability of both phases increasing with an increase in flow rate. The relative permeability rate effect was still evident as the IFT increased by an order of magnitude, with the relative permeability of the gas phase reducing more than the condensate phase. The influence of end effects was shown to be negligible at the IFT conditions used in the tests, with the Reynolds number indicating that flow was well within the so called laminar regime at all test conditions. The observed rate effect was contrary to that of the conventional non-Darcy flow where the effective permeability should decrease with increasing flow rate. A generalised correlation between relative permeability, velocity and IFT has been proposed, which should be more appropriate for condensing fluids than the conventional correlation. The results highlight the need for appropriate experimental methods and relative permeability relations where the distribution of the phases are representative of those in gas condensate reservoirs. This study will be particularly applicable to the vicinity of producing wells, where the rate effect on gas relative permeability can significantly affect well productivity. The findings provide previously unreported data on relative permeability and recovery of gas condensate fluids at realistic conditions. Introduction During the production of gas condensate reservoirs, the reservoir pressure will be gradually reduced to below the dew-point, giving rise to retrograde condensation. In the vicinity of producing wells where the rate of pressure reduction is greatest, the increase in the condensate saturation from zero is accompanied by a reduction in relative permeability of gas, due to the loss of pore space available to gas flow. It is the perceived effect of this local condensate accumulation on the near wellbore gas and condensate mobility that is one of the main areas of interest for reservoir engineers. The availability of accurate relative permeability data applicable to flow in the wellbore region impacts the management of gas condensate reservoirs.
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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 in Northern Croatia (and more generally in Drava Basin), as it contains about 50% CO2 (mole). Reservoir simulations of history-matched model showed base case (production without injection) and several cases of CO2 enhanced gas recovery, but with a focus on CO2 storage rather than maximizing hydrocarbon gas production achieved by converting a production well to a CO2 injection well. General findings are that even in gas reservoirs with such extreme initial CO2 content, gas production with CO2 injection can be carbon-negative. In almost all simulated CO2 injection scenarios, the process is carbon-negative from the time of CO2 injection, and in scenarios where CO2 injection begins earlier, it is carbon-negative from the start of gas production, which opens up the possibility of cost-effective storage of CO2 while producing natural gas with net negative CO2 emissions.
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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 the dew point. Accordingly, different regions with different characteristics are formed within the reservoir. These regions can be recognized by pressure transient analysis. Consequently, distinguishing between reservoir effects and fluid effects is challenging in these specific reservoirs and needs numerical simulation. The main objective of this paper is to examine the effect of condensate banking on the pressure behavior of lean and rich gas condensate NFRs through a simulation approach. Subsequently, evaluation of early-time characteristics of the pressure transient data is provided through a single well compositional simulation model. Then, drawdown, buildup, and multirate tests are conducted to establish the condition in which the flowing bottom-hole pressure drops below the dew point causing retrograde condensation. The simulation results are confirmed through well test analysis in both Iranian naturally fractured rich and lean gas condensate fields. Interpretations of simulation analysis revealed that the richer gas is more prone to condensation. When the pressure drops below the dew point, the pressure derivative curves in the rich gas system encounter a more shift to the right, and the trough becomes more pronounced as compared to the lean one.
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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 condensate fields. The EGR methods included the injection of dry gas (methane), hydrocarbon solvents (gas enriched with C2–C4 components), or nitrogen and carbon dioxide. The most commonly used and proven method is dry gas injection, which can be applied at any stage of the field’s development. Dry gas and intra-well cycling was done on five Ukrainian reservoirs, but because of the need to block significant volumes of sales gas they are not being considered for commercial application. Nitrogen has a number of significant advantages, but the fact that it increases the dew point pressure makes it applicable only at the early stage, when the reservoir pressure is above or near the dew point. Carbon dioxide is actively used for enhanced oil recovery (EOR) or for geological storage in depleted gas reservoirs. In light of the growing need to reduce carbon footprints, CO2 capture and sequestration is becoming very favourable, especially due to the low multi-contact miscibility pressure, the high density under reservoir conditions, and the good miscibility with formation water. All of these factors make it a good candidate for depleted gas condensate reservoirs.
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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 large fracture width in the simulations underestimates the effect of non-Darcy flow in hydraulic fractures. Various other factors governing the productivity improvement such as fracture length, fracture conductivity, well flow rates, and reservoir parameters have been analyzed. Productivity improvements were found to be overestimated by a factor as high as three, if non-Darcy flow was neglected. Results are presented that show the impact of condensate buildup on long-term productivity of wells in both rich and lean gas-condensate reservoirs. Introduction A significant decline in productivity of gas-condensate wells has been observed, resulting from a phenomenon called condensate blocking. Pressure gradients caused by fluid flow in the reservoir are greatest near the production well. As the pressure drops below the dewpoint pressure, liquid drops out and condensate accumulates near the well. This buildup of condensate is referred to as a condensate bank. The condensate continues to accumulate until a steady-state two-phase flow of condensate and gas is achieved. This condensate buildup decreases the relative permeability to gas, thereby causing a decline in the well productivity. Afidick et al. (1994) studied the Arun field in Indonesia, which is one of the largest gas-condensate reservoirs in the world. They concluded that a significant loss in productivity of the reservoir after 10 years of production was caused by condensate blockage. They found that condensate accumulation caused well productivity to decline by approximately 50%, even for this very lean gas. Boom et al. (1996) showed that even for a lean gas (e.g., less than 1% liquid dropout) a relatively high liquid saturation can build up in the near-wellbore region. Liquid saturations near the well can reach 50 to 60% under pseudosteady-state flow of gas and condensate (Cable et al. 2000; Henderson et al. 1998). Hydraulic fracturing of wells is a common practice to improve productivity of gas-condensate reservoirs. Modeling of gas-condensate wells with a hydraulic fracture requires taking into account non-Darcy flow. Gas velocity inside the fracture is three to four orders of magnitude higher than that in the matrix. Use of Darcy's law to model this flow can overestimate the productivity improvement. Therefore, it is necessary to use Forchheimer's equation to model this flow with an appropriate non-Darcy coefficient that takes into account the gas-relative permeability and water saturation.
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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 reservoir abandonment pressures.Calculation of black oil PVT parameters by the method of Coats (1985) is shown to be preferred over conventional approaches, although the PVT parameters themselves lose direct physical meaning. It is essential that a properly tuned equation of state be available for use in conjunction with experimental data.Production forecasting based on simulation output requires further processing in order to translate the black oil surface phase fluxes into products such as sales gas, LPG and condensate. For gas-condensate reservoirs, such post-processing of results from the simulation of depletion or cycling above the dew point is valid. In principle it is invalid for cycling below the dew point but in practice it can still provide useful information.
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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 dispersion. The miscibility conditions based on the traditional vaporizing-gas-drive (VGD) mechanism are also given for the sake of comparison, where it is typically found that this mechanism overpredicts conditions of miscibility. Significant variations in MMP and MME with depth exist for reservoirs with typical compositional gradients, particularly for near-critical oil reservoirs and gas-condensate reservoirs where the C/V mechanism exists. An important practical implication of these results is that miscible displacement in gas-condensate reservoirs can be achieved far below the initial dewpoint pressure. The requirement is that the injection gas (slug) be enriched somewhat beyond a typical separator gas composition and that the C/V miscibility mechanism exist. This behavior results in many more gas-condensate reservoirs being viable candidates for miscible gas cycling than previously assumed, and at cycling conditions with lower cost requirements (i.e., lower pressures) and greater operational flexibility (e.g., cycling only during summer months). Introduction Considerable work on miscible gas injection in oil and, to a lesser extent, gas-condensate reservoirs can be found in the literature.1,2 The phenomena of compositional variation with depth owing to gravity and thermal effects has also been studied in detail the past 20 years.3,4 However, almost nothing in the literature can be found on the variation of miscibility conditions with depth in reservoirs with compositional gradients. It is difficult to picture the variation of MMP with depth for a reservoir with varying composition and temperature. This study shows that a simple variation does not exist, but that certain features of MMP variation are characteristic for most reservoirs. For example, the simplest variation in MMP with depth is for a lean injection gas like nitrogen, where minimum miscibility conditions are developed by a purely VGD mechanism. Here the MMP is always greater than or equal to the saturation pressure. In the oil zone, MMP may be (and usually is) greater than the bubblepoint pressure, while in the gas zone the MMP is always equal to the dewpoint. The MMP variation with depth can be considerably more complicated when the injection gas contains sufficient quantities of light-intermediate components (C2 through C5) or CO2. Here, developed miscibility is usually by the condensing/vaporizing mechanism, but it may be purely vaporizing in some depth intervals of the reservoir. When the C/V mechanism exists, MMP may be (and often is) less than the saturation pressure, even for gas-condensate systems. This study quantifies the variation of MMP with depth for several reservoir-fluid systems, and we try to understand the reasons for seemingly complicated MMP variation. Perhaps the most important result of our study has been to show that miscible gas injection in gas-condensate reservoirs can exist far below the dewpoint. Economic application of enriched gas injection in partially depleted gas-condensate reservoirs may be achieved by slug injection, similar to miscible slug-injection projects in oil reservoirs.5 Calculating Minimum Miscibility Pressure Miscibility between a reservoir fluid and an injection gas usually develops through a dynamic process of mixing, with component exchange controlled by phase equilibria (K-values) and local compositional variation along the path of displacement. The exact process of mixing is not really important to the development of miscibility - i.e., the relative mobilities (permeabilities) of flowing phases are unimportant. However, to obtain the correct MMP it is important to follow a physically realistic path of developed miscibility and not assume a priori how the path to miscibility occurs. The ability of an EOS to predict minimum miscibility conditions and compositional grading is very dependent on the accurate representation of complex phase behavior and, in particular, accurate K-value predictions.4,6,7 Single-Cell Algorithms. Before 1986, it was assumed that developed miscibility followed one of two paths: Forward contact, or VGD, where the injection gas becomes enriched in C2+ by multiple contacts with original oil and, at the gas front, eventually develops miscibility with the original oil; or backward contact, or condensing gas drive (CGD), where the injection gas continuously enriches the reservoir oil in C2-C5 at the point of injection until the injection gas and enriched reservoir oil become miscible. Either process can be modeled with a single-cell calculation algorithm,8,9 where the critical tie-line is located by appropriate multiple contacts of injection gas and reservoir oil. For gas condensates, the vaporizing mechanism has always been assumed to exist in miscible gas-cycling projects and the VGD MMP is readily shown to equal the original dewpoint pressure. For reservoir oils, it is usually assumed that the VGD mechanism exists for lean injection gases, while the CGD has been assumed to describe miscible displacement for enriched gas injection. Using a single-cell calculation algorithm, the calculated VGD MMP is almost always lower than or equal to the CGD MMP, unless the gas is highly enriched. C/V Mechanism. Zick6 showed that a mixed mechanism involving both vaporization and condensation describes the actual development of minimum miscibility conditions for many systems. He showed that the location of miscibility (i.e., near-100% recovery efficiency) was not at the displacement front (VGD) or the point of injection (CGD), but in between. He also showed that the true minimum conditions of miscibility could be significantly lower than predicted by the VGD and CGD mechanisms. These findings have been verified by numerous publications during the past 10 years.7,10–12 Based on Zick's findings and his description of the mixed C/V mechanism, it is clear that the true MMP (or MME) can be calculated only if the path of developed miscibility is modeled properly. Several authors have suggested methods to calculate the C/V MMP.
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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 were conducted, including chemical injection, routine core analysis, and nuclear magnetic resonance (NMR) measurements. The impact of thermochemical treatment in sustaining gas production from a tight gas reservoir was quantified. This study demonstrates that thermochemical treatment can create different types of fractures (single or multistaged fractures) based on the injection method. Thermochemical treatment can increase absolute permeability up to 500%, reduce capillary pressure by 57%, remove the accumulated liquids, and improve gas relative permeability by a factor of 1.2. The findings of this study can help to design a better thermochemical treatment for improving gas recovery. This study showed that thermochemical treatment is an effective method for sustaining gas production from tight gas reservoirs.
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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 results indicate that hydrocarbon reservoir types in the Upper Ordovician of the Tazhong Area transition from unsaturated to saturated condensate-gas reservoirs from west to east and from condensate-gas reservoirs to unsaturated-oil reservoirs from north to south. The crude oil in the region originated primarily from the mixing of Lower–Middle Cambrian and Middle–Upper Ordovician source rocks, while the natural gas was sourced primarily from the cracking gas of Lower–Middle Cambrian crude oil. This hydrocarbon-phase distribution was controlled primarily by temperature and pressure and has been affected by multiple periods of hydrocarbon accumulation and alteration. The high-quality Lower–Middle Cambrian reservoir–cap assemblage may be an important target for future exploration of natural gas in the Tazhong Area.
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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 identification method and various empirical statistical methods, such as the block diagram method, φ 1 parameter method, rank number method, and Z -factor method were implemented to comprehensively identify the phase behavior types of the BZ19-6 condensate gas reservoir. The genetic mechanism of the BZ19-6 condensate gas reservoir was investigated in detail through analyses of physical properties of the fluid at high temperatures and pressures, organic geochemical characteristics of condensate oil and gas, and regional tectonic background. Consequently, this study is shown as follows: (1) The BZ19-6 condensate gas reservoir is a part of a secondary condensate gas reservoir with oil rings, formed synthetically since the Neogene period due to multiple factors, such as retrograde evaporation from deep burial and high temperature, inorganic CO2 charging from the deep mantle, and late natural gas invasion. (2) The hydrocarbon accumulation process of the BZ19-6 condensate gas reservoir is as follows: First, a large amount of oil is accumulated at the end of the lower Minghuazhen deposition (5 Ma BP); second, a large amount of natural gas is generated in the deep-source kitchen and mantle-derived inorganic CO2 charged into the early formed oil reservoirs at the end of the upper Minghuazhen deposition (2 Ma BP). As a result, the content of gaseous hydrocarbons in the hydrocarbon system of the reservoir increased, which led to large amounts of liquid hydrocarbons dissolved in gaseous hydrocarbons and significantly reduced the critical temperature of the hydrocarbon system. Therefore, existing secondary condensate gas reservoirs are formed when the critical temperature is lower than the formation temperature and it enters the critical condensate temperature range.
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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 conducted two sets of tests simulating the effect(s) of gas-/liquid-phase fractionation on fingerprinting analyses:at different pressures (all below the dewpoint) at reservoir temperature (RT) region in order to simulate dropout of liquids in the near-wellbore area andto investigate the effect of variations in separator temperature and pressure. Geochemical fingerprints obtained on our laboratory-fractionated samples show that condensates obtained from gas wells with flowing bottomhole pressures below dewpoint may not be suitable for compartmentalization studies. Differences in separator pressure and temperature affect the fingerprints of gas condensates, but the effects are small and unlikely to alter conclusions regarding potential fluid-flow barriers. We suggest a number of best practices for the collection and analysis of gas condensates for fingerprinting studies.
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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 aspects of percolation mechanics, gas reservoir engineering and numerical simulation. considering there exist the start-up pressure gradient in percolation process of low permeability gas reservoir, this paper combined with productivity equation under starting pressure gradient, established the formula of gas well spacing with the formation pressure and start-up pressure gradient. The calculation formula of starting pressure gradient and well spacing of gas wells. Adopting various methods to calculate values of gas reservoir spacing are close to well testing' radius, so the calculation method is reliable, which is very important for the determination of reasonable well spacing in low permeability gas reservoirs.
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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. The synthesized surfactant was characterized by Fourier transform infrared spectroscopy and thermogravimetric analysis. Then, using surface tension tests, its critical micelle concentration (CMC) was determined. Contact angle experiments on chemically treated sections with surfactant solutions and spontaneous imbibition were performed to investigate the wettability alteration. Surfactant adsorption on porous media was calculated using flooding. Finally, the surfactant foamability was investigated using a Ross–Miles foam generator. According to the results, the synthesized surfactant has suitable thermal stability for use in gas condensate reservoirs. A CMC of 3500 ppm was obtained for the surfactant based on the surface tension experiments. Contact angle experiments show the ability of the surfactant to chemical treatment and wettability alteration of carbonate rocks to gas-wet so that at the constant concentration of CMC and at 373 K, the contact angles at treatment times of 30, 60, 120 and 240 min were obtained 87.94°, 93.50°, 99.79° and 106.03°, respectively. However, this ability varies at different surfactant concentrations and temperatures. The foamability test also shows the suitable stability of the foam generated by the surfactant, and a foam half-life time of 13 min was obtained for the surfactant at CMC.
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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 condensate droplets immersed in brine under the influence of electric current need to be understood. A laboratory experiment was designed to capture the effect of electrical current on interfacial tension and droplet movement. Pendant drop tensiometry was used to obtain the interfacial tension, while force analysis was used to analyze the effect of the electrical current on droplet trajectory. Salinity (0–23 ppt) and electric voltage (0–46.5 V) were the main variables during the entire experiment. Results from the experiment reveal an increase in IFT as the voltage is increased, while the droplet trajectory was significantly altered with an increase in voltage. This study concludes that the interfacial tension increases progressively with an increase in DC current, until its effect counteracts the benefit obtained from the preferential movement of condensate droplet.
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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 saturated with mathane. Clear differences in AVO response exist between hydrocarbon‐saturated reservoirs and those containing brine. However, it is also interesting that “subtle” but noticeable differences can be interpreted between condensate‐and methane‐saturated sands. These differences are attributed to differences in both in‐situ fluid density and compressibility, and rock frame properties.
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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 studies evaluate the method’s performance for condensing flows, typical of gas-condensate reservoirs. In this context, we present a compositional pore-network model for gas-condensate flow under variable wetting conditions. Different condensate modes and flow patterns based on experimental observations were implemented in the model so that the effects of wettability on condensing flow were represented. Flow analyses under several thermodynamic conditions and flow rates in a sandstone based network were conducted to determine the parameters affecting condensate blockage mitigation by wettability alteration. Relative permeability curves and impacts factors were calculated for gas flowing velocities between 7.5 and 150 m/day, contact angles between 45° and 135°, and condensate saturations up to 35%. Significantly different relative permeability curves were obtained for contrasting wettability media and impact factors below one were found at low flowing velocities in preferentially gas-wet cases. Results exhibited similar trends observed in coreflooding experiments and windows of optimal flow enhancement through wettability alteration were identified.
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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 multiphase-pressure-diffusivity equation to analyze multiphase flow in single- and dual-porosity models of unconventional reservoirs. Our approach is similar to the work presented by Perrine (1956); however, our approach has a theoretical foundation, whereas Perrine (1956) used pragmatic engineering analogy for constant flow rate in vertical wells only. In addition to oil, gas, and formation brine, our method accounts for gas/condensate production, and the flowback of the injected hydraulic-fracturing fluids. Overall, our proposed approach is more comprehensive than the single-phase models but maintains the simplicity of the conventional methods. Our paper includes diagnostic plots of rate-normalized well pressure for light oils and gas/condensates in unconventional reservoirs. Data from two Bakken and two Eagle Ford wells will be presented to demonstrate the usefulness of our approach. In addition to the mathematical analysis of flow-rate and pressure data, we will present the effect of well-stimulation and fluid-lift methods on the flow-rate characteristics of Bakken and Eagle Ford wells.
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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 simulated. And using the modified PR EOS, PR EOS, and nonequilibrium effect theory, the authors calculated the content of condensate oil and condensate liquid of the nonequilibrium pressure drop and equilibrium pressure drop and compared the calculated results with the experimental data. The results show that the modified PR EOS combined with nonequilibrium effect theory is more suitable for representing phase behavior characteristics of the development process of condensate gas reservoir containing gaseous water, with the average relative error of 4.49%. Furthermore, choosing the appropriate exploiting opportunity and properly increasing the nonequilibrium effect are helpful to increase condensate oil and water recovery.
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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 the evaluation of a gas condensate reservoir performance of Akpet GT 9 Reservoir in the Niger Delta region of Nigeria with material balance analysis tool “MBal” without having to run numerical simulations. The result obtained with MBal on the analysis of Akpet GT 9 reservoir gave 23.934 Bscf of gas initially in place which compares favorably with the volume obtained from volumetric techniques. Results also shows that the most likely aquifer model is the Hurst–Van Everdingen - Dake radial aquifer and the reservoir is supported by a combined drive of water influx and fluid expansion.
 Okotie, S. | Department of Petroleum Engineering, Federal University of Petroleum Resources (FUPRE), Effurun, Delta State, Nigeria.
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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 dimensionless fracture conductivity and Stimulated Reservoir Volume (SRV) designs of lean and rich condensate compositions are studied. Well productivity and saturation profile of each design had been observed. The results from this study indicate that the higher dimensionless fracture conductivity gives the higher well productivity in every studied parameter in lean condensate composition. However, in rich condensate composition shows different trend of results because it has higher heavy ends (C7+) that drop into liquid easier once pressure falls below dew point pressure. The maximum number of fracture and fracture permeability can be recognized in the study of rich condensate. In the study of SRV indicates that number of fracture is superior to fracture width in both gas and condensate productivity. Moreover, performing hydraulic fracturing can decrease pressure drawdown, production time and liquid dropout which leads to the mitigation of condensate banking near wellbore that can be recognized in the study of condensate saturation profile.
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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 reservoir properties of reservoir rocks and increasing the flow of hydrocarbons. To select the optimal technology and composition for conducting water shutoff treatment, it is necessary to take into account the following factors: which reservoirs represent the reservoir, the percentage of water cut in the recoverable reserves, the tightness of the production string, the current flow rate of the well during operation at constant reservoir pressure, because each field needs an individual approach with a choice suitable water shuto-ff treatment technology.
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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 predictive field simulations as illustrated in this article. Introduction Afidick et al.1 and Barnum et al.2 have reported field data which show that under some conditions a significant loss of well productivity can occur in gas wells due to near wellbore condensate accumulation. As pointed out by Boom et al.,3 even for lean fluids with low condensate dropout, high condensate saturations may build up as many pore volumes of gas pass through the near wellbore region. As the condensate saturation increases, the gas relative permeability decreases and thus the productivity of the well decreases. The gas relative permeability is a function of the interfacial tension (IFT) between the gas and condensate among other variables. For this reason, several laboratory studies3–14 have been reported on the measurement of relative permeabilities of gas-condensate fluids as a function of interfacial tension. These studies show a significant increase in the relative permeability of the gas as the interfacial tension between the gas and condensate decreases. The relative permeabilities of the gas and condensate have often been modeled directly as an empirical function of the interfacial tension.15 However, it has been known since at least 194716 that the relative permeabilities in general actually depend on the ratio of forces on the trapped phase, which can be expressed as either a capillary number or Bond number. This has been recognized in recent years to be true for gas-condensate relative permeabilities.8,10 The key to a gas-condensate relative permeability model is the dependence of the critical condensate saturation on the capillary number or its generalization called the trapping number. A simple two-parameter capillary trapping model is presented that shows good agreement with experimental data. This model is a generalization of the approach first presented by Delshad et al.17 We then present a general scheme for computing the gas and condensate relative permeabilities as a function of the trapping number, with only data at low trapping numbers (high IFT) as input, and have found good agreement with the experimental data in the literature. This model, with typical parameters for gas condensates, was used in a compositional simulation study of a single well to better understand the productivity index (PI) behavior of the well and to evaluate the significance of condensate buildup. Model Description The fundamental problem with condensate buildup in the reservoir is that capillary forces can retain the condensate in the pores unless the forces displacing the condensate exceed the capillary forces. To the degree that the pressure forces in the displacing gas phase and the buoyancy force on the condensate exceed the capillary force on the condensate, the condensate saturation will be reduced and the gas relative permeability increased. Brownell and Katz16 and others recognized early on that the residual oil saturation should be a function of the ratio of viscous to interfacial forces and defined a capillary number to capture this ratio. Since then many variations of the definition have been published,17–20 with some of the most common ones written in terms of the velocity of the displacing fluid, which can be done by using Darcy's law to replace the pressure gradient with velocity. However, it is the force on the trapped fluid that is most fundamental and so we prefer the following definition: N c l = | k → → ⋅ ∇ → ϕ l | σ l l ′ , ( 1 ) where definitions and dimensions of each term are provided in the nomenclature. Although the distinction is not usually made, one should designate the displacing phase l ? and the displaced phase l in any such definition. In some cases, buoyancy forces can contribute significantly to the total force on the trapped phase. To quantify this effect, the Bond number was introduced and it also takes different forms in the literature.20 One such definition is as follows: N B l = k g ( ρ l ′ − ρ l ) σ l l ′ . ( 2 ) For special cases such as vertical flow, the force vectors are collinear and one can just add the scalar values of the viscous and buoyancy forces and correlate the residual oil saturation with this sum, or in some cases one force is negligible compared to the other force and just the capillary number or Bond number can be used by itself. This is the case with most laboratory studies including the recent ones by Boom et al.3,8 and by Henderson et al.10 However, in general the forces on the trapped phase are not collinear in reservoir flow and the vector sum must be used. A generalization of the capillary and Bond numbers was derived by Jin 21 and called the trapping number. The trapping number for phase l displaced by phase l? is defined as follows: N T l = | k → → ⋅ ( ∇ → ϕ l ′ + g ( ρ l ′ − ρ l ) ∇ → D ) | σ l l ′ . ( 3 ) This definition does not explicitly account for the very important effects of spreading and wetting on the trapping of a residual phase. However, it has been shown to correlate very well with the residual saturations of the nonwetting, wetting, and intermediate-wetting phases in a wide variety of rock types.
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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 injection into a local fractured and faulted gas condensate reservoir in Western Australia. Tempest 6.6 compositional simulation model was used to evaluate the performance of uncertain reservoir parameters, injection design variables, and economic recovery factors associated with CO2 injection. The model incorporates experimental IFT, relative permeability data and solubility data at various thermodynamic conditions for the same field. These measurements preceded the simulation work and are now published in various places. The model uses Todd-Longstaff mixing algorithm to control the displacement front expansion. This paper will present, with aid of simulation output graph and tornado charts, the results of natural depletion, miscible and immiscible CO2 injection, waterflooding, WAG, sensitivity of fracture porosity, permeability and fracture intensity. The results also demonstrate the effect of initial reservoir composition, well completion and injection flow rate. All simulation cases were carried out at various injection pressures. The results are discussed in terms of transport mechanisms and fluid dynamics. This project was sponsored by a consortium of companies.
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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 introduced as a novel solvent for this purpose. In addition to good partitioning into condensate/gas/aqueous phases, DME has a high vapor pressure, which improves the flowback after the treatment. We compare its behavior with both methanol (MeOH) and ethanol (EtOH) solvents.
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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 between the PVT-derived gradient and that obtained from wellbore-flow modeling of production-test data. Older-generation formation testers (those from before 1990), although yielding comparable results, had larger error bars because of system limitations in repeatability of both pressure and depth measurements. We developed a yield/temperature correlation to fill in the information void for reservoirs that fall within the bounds of measured data over a large geographic area. Correlating CO2 with formation temperature was a stepping stone to the yield/temperature relationship. This approach is applicable for the analysis of both single-reservoir and multireservoir samples, which is particularly useful when rapid assessment is needed over large regions. Introduction The presence of a compositional gradient in reservoirs containing hydrocarbon columns has long been recognized since Sage and Lacey (1939) published their seminal work. Segregation of asphaltenes causes compositional grading in oil (20-30°API) columns. In contrast, compositional grading in light-hydrocarbon (> 35°API) columns occurs for near-critical fluids or, more appropriately, for fluids close to the spinodal curve (Lira-Galeana 1992). Equilibrium between gravitational and chemical forces of various hydrocarbon components results in a variable saturation pressure in a fluid column (Schulte 1980; Riemens et al. 1988; Wheaton 1991). According to Hirschberg (1988), the time to reach such an equilibrium (10 million to 1 billion years) is comparable to the geologic time of a typical reservoir. A number of authors have reported field experiences with compositional grading in gas/condensate reservoirs (Creek and Schrader 1985; Smith et al. 2004; Ghorayeb et al. 2003). Ordinarily, the equilibrium approach appears to explain gradients observed in the field. In reality, however, heat flux can potentially prevent attaining true equilibrium in a hydrocarbon column because of the temperature gradient in a reservoir (Pedersen and Lindeloff 2003; Hoier and Whitson 2001; Ghorayeb and Firoozabadi 2000a and 2000b; Firoozabadi 1999). Irreversible thermodynamics appears to explain compositional grading in most systems. In this study, we will assume that thermal diffusion does not play a dominant role in distributing hydrocarbon components in the fluid columns studied.
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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 reservoir environment. In fact, this algorithm is currently being utilized successfully with an optical spectrometer operating down-hole in oil wells.
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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 outflow correlations for wellbore behavior. An optimization algorithm was also used with the integrated model so it can be used in history-matching mode to estimate original gas in place (OGIP), original oil in place (OOIP), and productivity-index (PI) parameters for gas/condensate wells. The model also can be used to predict the production performance for variable tubinghead pressure (THP) and variable production rate. The model runs fast and requires minimal input. The developed model was validated by use of different simulation cases generated with a commercial compositional reservoir simulator for a variety of reservoir and well conditions. The results show a good agreement between the simulation cases and the integrated model. After validating the integrated model against the simulated cases, the model was used to analyze production data for a rich-gas/condensate field (initial condensate/gas ratio of 180 bbl/ MMscf). THP data for four wells were used along with basic reservoir and production data to obtain original fluids in place and PIs of the wells. The estimated parameters were then used to forecast the gas and condensate production above and below the dewpoint. The model is also capable of predicting reservoir pressure, bottomhole flowing pressure, and THP and can account for completion changes when they occur.
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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-wetting to intermediate gas-wetting at high reservoir temperatures,wettability alteration has a substantial effect on increasing liquid mobility at reservoir conditions,wettability alteration results in improved gas productivity, andwettability alteration does not have a measurable effect on the absolute permeability of the rock for some chemicals. We also find the reservoir rock, unlike Berea, is not strongly water-wet in the gas/water/rock system. Introduction A sharp reduction in gas well deliverability is often observed in many low-permeability gas-condensate reservoirs even at very high reservoir pressure. The decrease in well deliverability is attributed to condensate accumulation (Hinchman and Barree 1985; Afidick et al. 1994) and water blocking (Engineer 1985; Cimolai et al. 1983). As the pressure drops below the dewpoint, liquid accumulates around the wellbore in high saturations, reducing gas relative permeability (Barnum et al. 1995; El-Banbi et al. 2000); the result is a decrease in the gas production rate. Several techniques have been used to increase gas well deliverability after the initial decline. Hydraulic fracturing is used to increase absolute permeability (Haimson and Fairhurst 1969). Solvent injection is implemented in order to remove the accumulated liquid (Al-Anazi et al. 2005). Gas deliverability often increases after the reduction of the condensate saturation around the wellbore. In a successful methanol treatment in Hatter's Pond field in Alabama (Al-Anazi et al. 2005), after the initial decline in well deliverability by a factor of three to five owing to condensate blocking, gas deliverability increased by a factor of two after the removal of water and condensate liquids from the near-wellbore region. The increased rates were, however, sustained for a period of 4 months only. The approach is not a permanent solution to the problem, because the condensate bank will form again. On the other hand, when hydraulic fracturing is used by injecting aqueous fluids, the cleanup of water accumulation from the formation after fracturing is essential to obtain an increased productivity. Water is removed in two phases: immiscible displacement by gas, followed by vaporization by the expanding gas flow (Mahadevan and Sharma 2003). Because of the low permeability and the wettability characteristics, it may take a long time to perform the cleanup; in some cases, as little as 10 to 15% of the water load could be recovered (Mahadevan and Sharma 2003; Penny et al. 1983). Even when the problem of water blocking is not significant, the accumulation of condensate around the fracture face when the pressure falls below dewpoint pressure could result in a reduction in the gas production rate (Economides et al. 1989; Sognesand 1991; Baig et al. 2005).