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Burachok, Oleksandr. "Enhanced Gas and Condensate Recovery: Review of Published Pilot and Commercial Projects." Nafta-Gaz 77, no. 1 (January 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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Høier, Lars, and Curtis H. Whitson. "Miscibility Variation in Compositionally Grading Reservoirs." SPE Reservoir Evaluation & Engineering 4, no. 01 (February 1, 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, Mohamed Mahmoud, Abdulaziz Al-Majed, Ayman Al-Nakhli, Mohammed Bataweel, and Salaheldin Elkatatny. "Mitigation of Condensate Banking Using Thermochemical Treatment: Experimental and Analytical Study." Energies 12, no. 5 (February 28, 2019): 800. http://dx.doi.org/10.3390/en12050800.
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Condensate banking is a common problem in tight gas reservoirs because it diminishes the gas relative permeability and reduces the gas production rate significantly. CO2 injection is a common and very effective solution to mitigate the condensate damage around the borehole in tight gas reservoirs. The problem with CO2 injection is that it is a temporary solution and has to be repeated frequently in the field in addition to the supply limitations of CO2 in some areas. In addition, the infrastructure required at the surface to handle CO2 injection makes it expensive to apply CO2 injection for condensate removal. In this paper, a new permanent technique is introduced to remove the condensate by using a thermochemical technique. Two chemicals will be used to generate in situ CO2, nitrogen, steam, heat, and pressure. The reaction of the two chemicals downhole can be triggered either by the reservoir temperature or a chemical activator. Two chemicals will start reacting and produce all the mentioned reaction products after 24 h of mixing and injection. In addition, the reaction can be triggered by a chemical activator and this will shorten the time of reaction. Coreflooding experiments were carried out using actual condensate samples from one of the gas fields. Tight sandstone cores of 0.9 mD permeability were used. The results of this study showed that the thermochemical reaction products removed the condensate and reduced its viscosity due to the high temperature and the generated gases. The novelty in this paper is the creation of micro-fractures in the tight rock sample due to the in-situ generation of heat and pressure. These micro-fractures reduced the capillary forces that hold the condensate and enhanced the rock relative permeability. The creation of micro-fractures and in turn the reduction of the capillary forces can be considered as permanent condensate removal.
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Kondrat, O. R., and D. O. Shyshkina. "ENHANCEMENT OF CONDENSATE RECOVERY FACTOR FROM DEPLETED GAS CONDENSATE FIELDS." Prospecting and Development of Oil and Gas Fields, no. 4(69) (December 3, 2018): 23–36. http://dx.doi.org/10.31471/1993-9973-2018-4(69)-23-36.
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The efficiency of gas condensate fields additional development at the final stage was investigated. The feature of condensed hydrocarbon production at low reservoir pressures is analyzed and the effectiveness of methods for increasing condensate recovery from depleted gas condensate fields is considered.
The theoretical model of the simplified depleted gas condensate field with homogeneous volume and reservoir properties is developed. The study involves processes of the gas condensate recovery from depleted gas condensate fields enhancement through the injection of dry hydrocarbon gas, nitrogen, carbon dioxide gas into a bed, fringe of the propane-butane fraction with its transfer along the bed through nitrogen and by flooding are investigated using the hydrodynamic simulator Eclipse 300. The effectiveness of various placements of injection wells and the active reservoir water effect on the gas condensate field exploitation are outlined.
The research proved that the placement of injection wells in the contour zone is the most effective when reservoir water active contour is available.
In general, the introduction of methods for condensate recovery enhancement in gas condensate fields with high level of condensate should be carried out from the beginning of the field exploitation to prevent the loss of hydrocarbons because of retrograde condensation. The effect of introducing methods for the condensate recovery enhancement is relatively inconsiderable in the depleted gas condensate fields.
Carbon dioxide turned out to be displacing agent. Its injection in the contour part of the field is recommended, in particular, this value will be even higher if the active water bed is not available.
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Belhaj, Hadi. "Management of injected nitrogen into a gas condensate reservoir." Ingeniería e Investigación 36, no. 1 (April 18, 2016): 52–61. http://dx.doi.org/10.15446/ing.investig.v36n1.50319.
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<p>This study investigates the means of deferring the breakthrough of injected N2 and alleviating the impact of such on production rates and specifications as well as minimizing the required changes to the gas processing facilities. This aimed at assisting the ongoing efforts to transfer the Cantarell experience to Abu Dhabi, where large amounts of N2 gas will be generated and injected into a large gas condensate reservoir to partially substitute the recycling of lean gas. This will bring forward the opportunity to exploit lean gas by securing base load supplies before the start of reservoir blowdown, compared to the peak shaving approach currently practiced. Managing N2 breakthrough starts by better understanding the pattern at which N2 injection spreads into the gas accumulation. Based on the findings of initial subsurface and plant simulations carried out in 2008, N2 breakthrough in Abu Dhabi might be possibly deferred by segmenting the reservoir into a rich N2 region and lean N2 region. The approach assumes no thief zones will be faced and no channeling of N2 injected between the two regions is taking place. N2 is injected in the north region of the reservoir. The production of that region will be segregated and fed to a gas processing plant of lower NGL (natural gas liquid) recovery, which essentially takes longer time to start suffering the deterioration of residue gas (gas mixture resulted after separating NGL) quality. The residue gas use can be limited to re-injection where the effect of below specification LHV (Low Heat Value) would not be an issue. The rest of the reservoir feeds another gas processing plant of higher NGL recovery level from which an amount of residue gas equivalent to that of the injected N2 will be rerouted to the sales network. This scenario will significantly delay as well as downsize the requirement of a N2 rejection plant. There is technical and certainly economical advantage of deferring the installation of costly N2 rejection units. Such a requirement can be entirely eliminated if the sales gas specification can be relaxed considering blending with other gas streams of higher LHV, and in collaboration with gas customers, i.e. assessing their capability to tolerate feedstock of lower specifications. It must be noted that such school of thinking may not necessarily be eventually embraced. The chosen scenario will also depend on the final configuration, i.e., wells grouping and gas gathering, of the ongoing project.</p>
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Lü, Xiuxiang, Jianfa Han, Xiang Wang, Weiwei Jiao, Hongfeng Yu, Xiaoli Hua, Haizu Zhang, and Yue Zhao. "Hydrocarbon Distribution Pattern in the Upper Ordovician Carbonate Reservoirs and its Main Controlling Factors in the West Part of Northern Slope of Central Tarim Basin, NW China." Energy Exploration & Exploitation 30, no. 5 (October 2012): 775–92. http://dx.doi.org/10.1260/0144-5987.30.5.775.
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The northern slope of Tazhong palaeo-uplift has become a key target field for petroleum exploration in Tarim Basin. A major breakthrough is made in the Upper Ordovician oil and gas exploration in the west part of northern slope. Oil and gas near the Tazhong I slope-break zone occurred in Liang2 section was dominated by condensate gas reservoir, while oil reservoir was mainly inward distributed in Liang3 section. The crude oils in this region in physical properties characterized by low density, low viscosity, low freezing point, low sulfur content, medium wax content. And the natural gas in chemical components was featured by low-medium nitrogen content, low-medium carbon dioxide content and medium-high hydrogen sulfide content. In the plane direction, oil and gas exhibited a “oil in the interior, gas in the exterior” distribution pattern, and mainly located in a depth range of 0∼60 m below the top of the Liang3 section in the longitudinal direction. The distribution patterns displayed in physical properties and chemical compositions of oil and gas are controlled by multiple influencing factors. The results of above comprehensive studies suggested that vertical overriding of reef-bank-type reservoirs in Liang2 section and karst reservoirs in Liang3 section provided superior reservoir conditions; faults and fractures not only formed reservoir space and improved reservoir quality, also promoted the development of karst reservoirs and provided good migration pathway for hydrocarbon accumulation; one of the nonnegligible factors leading to this kind of distribution pattern for the Upper Ordovician oil and gas reservoirs is shale content in the compact carbonate formation; multi-sources and multi-stages of hydrocarbon filling are absolutely necessary controlling factor for this kind of distribution pattern in the whole block.
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Matkivskyi, Serhii, and Oleksandr Kondrat. "The influence of nitrogen injection duration at the initial gas-water contact on the gas recovery factor." Eastern-European Journal of Enterprise Technologies 1, no. 6 (109) (February 10, 2021): 77–84. http://dx.doi.org/10.15587/1729-4061.2021.224244.
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This paper reports a study that employed a digital three-dimensional model of the gas condensate reservoir to investigate the process of nitrogen injection at the boundary of initial gas-water contact at different values of the injection duration. The calculations were performed for 5, 6, 8, 10, 12 and 14 months injection duration. Based on the modeling results, it was found that increasing the duration of the nitrogen injection decreases the operation time of production wells until the breakthrough of non-hydrocarbon gas. Based on the analysis of the technological indicators of reservoir development, it was established that the introduction of technology of the nitrogen injection into a reservoir ensures a reduction in the volume of reservoir water production. The cumulative water production at the time of nitrogen breakthrough to the production wells at the nitrogen injection duration of 5 months is 197,3 thousand m3; of 14 months – 0,038 m3. According to the results from the statistical treatment of estimation data, the optimal value for the nitrogen injection duration was determined, which is 8,04 months. The ultimate gas recovery factor for the optimal period of the non-hydrocarbon gas injection is 58,11 %, and in the development of a productive reservoir for depletion – 34,6 %. Based on the research results, the technological efficiency of nitrogen injection into a productive reservoir has been determined at the boundary of initial gas-water contact in order to slow the movement of reservoir water into gas-saturated horizons. This study results allow the improvement of the existing technologies of hydrocarbon fields development under conditions of water drive. The use of the results of the research carried out in production will make it possible to reduce the volume of cumulative water production and increase the ultimate gas recovery factors to 23,51 %
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Glennie, K. W. "Exploration activities in the Netherlands and North-West Europe since Groningen." Netherlands Journal of Geosciences - Geologie en Mijnbouw 80, no. 1 (April 2001): 33–52. http://dx.doi.org/10.1017/s0016774600022150.
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AbstractOnce the great size of the Groningen Field was fully realized late in 1963, exploration in the southern North Sea was a natural development as the reservoir bedding dipped westward. The origin of that bedding was not certain, one possibility, dune sands, led immediately to a program of desert studies.Licensing regulations for Netherlands waters were not finalized until 1967, offshore exploration beginning with the award of First Round licenses in March 1968. In the UK area, the Continental Shelf Act came into force in May 1964, paving the way for offshore seismic, the first well being spudded late in that year. The first two wells were drilled on the large Mid North Sea High; both were dry, the targeted Rotliegend sandstones being absent. Then followed a series of Rotliegend gas discoveries, large and small, west of Groningen, so that by the time exploration began in Netherlands waters the UK monopoly market was saturated and exploration companies were already looking north for other targets including possible oil.The Rotliegend was targeted in the earliest wells of the UK central North Sea even though there had already been a series of intriguing oil shows in Chalk and Paleocene reservoirs in Danish and Norwegian waters. These were followed early in 1968 by the discovery of gas in Paleocene turbidites at Cod, near the UK-Norway median line. The first major discovery was Ekofisk in 1969, a billion-barrel Maastrichtian to Danian Chalk field. Forties (1970) confirmed the potential of the Paleocene sands as another billion barrel find, while the small Auk Field extended the oil-bearing stratigraphy down to the Permian. In 1971, discovery of the billion-barrel Brent field in a rotated fault block started a virtual ‘stampede’ to prove-up acreage awarded in the UK Fourth Round (1972) before the 50% statutory relinquishment became effective in 1978.Although the geology of much of the North Sea was reasonably well known by the end of the 1970s, new oil and gas reservoirs continued to be discovered during the next two decades. Exploration proved the Atlantic coast of Norway to be a gas and gas-condensate area. The stratigraphiC range of reservoirs extended down to the Carboniferous (gas) and Devonian (oil), while in the past decade, forays into the UK Atlantic Margin and offshore Ireland met with mixed success. During this hectic activity, Netherlands exploration confirmed a range of hydrocarbon-bearing reservoirs; Jurassic oil in the southern Central Graben, Jurassic-Cretaceous oil derived from a Liassic source mainly onshore and, of course, more gas from the Rotliegend. German exploration had mixed fortunes, with no commercial gas in the North Sea and high nitrogen content in Rotliegend gas in the east. Similarly in Poland, where several small Zechstein oil fields were discovered, the Rotliegend gas was nitrogen rich. The discovery of some 100 billion barrels of oil and oil equivalent beneath the waters of the North Sea since 1964 led to an enormous increase in geological knowledge, making it probably the best known area of comparable size in the World. The area had a varied history over the past 500 million years: platete-tonic movement, faulting, igneous activity, climatic change, and deposition in a variety of continental and marine environments, leading to complex geometrical relationships between source rock, reservoir and seal, and to the reasons for diagenetic changes in the quality of the reservoir sequences. Led by increasingly sophisticated seismic, drilling and wireline logging, and coupled with academic research, the North Sea developed into a giant geological laboratory where ideas were tested and extended industry-wide.
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Pang, Zhanxi, Lei Wang, Zhengbin Wu, and Xue Wang. "An Investigation Into Propagation Behavior of the Steam Chamber During Expanding-Solvent SAGP (ES-SAGP)." SPE Journal 24, no. 02 (January 9, 2019): 413–30. http://dx.doi.org/10.2118/181331-pa.
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Summary Steam-assisted gravity drainage (SAGD) and steam and gas push (SAGP) are used commercially to recover bitumen from oil sands, but for thin heavy-oil reservoirs, the recovery is lower because of larger heat losses through caprock and poorer oil mobility under reservoir conditions. A new enhanced-oil-recovery (EOR) method, expanding-solvent SAGP (ES-SAGP), is introduced to develop thin heavy-oil reservoirs. In ES-SAGP, noncondensate gas and vaporizable solvent are injected with steam into the steam chamber during SAGD. We used a 3D physical simulation scale to research the effectiveness of ES-SAGP and to analyze the propagation mechanisms of the steam chamber during ES-SAGP. Under the same experimental conditions, we conducted a contrast analysis between SAGP and ES-SAGP to study the expanding characteristics of the steam chamber, the sweep efficiency of the steam chamber, and the ultimate oil recovery. The experimental results show that the steam chamber gradually becomes an ellipse shape during SAGP. However, during ES-SAGP, noncondensate gas and a vaporizable solvent gather at the reservoir top to decrease heat losses, and oil viscosity near the condensate layer of the steam chamber is largely decreased by hot steam and by solvent, making the boundary of the steam chamber vertical and gradually a similar, rectangular shape. As in SAGD, during ES-SAGP, the expansion mechanism of the steam chamber can be divided into three stages: the ascent stage, the horizontal-expansion stage, and the descent stage. In the ascent stage, the time needed is shorter during ES-SAGP than during SAGP. However, the other two stages take more time during nitrogen, solvent, and steam injection to enlarge the cross-sectional area of the bottom of the steam chamber. For the conditions in our experiments, when the instantaneous oil/steam ratio is lower than 0.1, the corresponding oil recovery is 51.11%, which is 7.04% higher than in SAGP. Therefore, during ES-SAGP, not only is the volume of the steam chamber sharply enlarged, but the sweep efficiency and the ultimate oil recovery are also remarkably improved.
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Carpenter, Chris. "Technique Proves Effective in Remediation of Phase-Trapping Damage in Tight Reservoirs." Journal of Petroleum Technology 73, no. 07 (July 1, 2021): 60–61. http://dx.doi.org/10.2118/0721-0060-jpt.
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This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 202996, “An Efficient Treatment Technique for Remediation of Phase-Trapping Damage in Tight Carbonate Gas Reservoirs,” by Rasoul Nazari Moghaddam, SPE, Marcel Van Doorn, and Auribel Dos Santos, SPE, Nouryon, prepared for the 2020 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, held virtually 9–12 November. The paper has not been peer reviewed. Aqueous- and hydrocarbon-phase trapping are among the few formation-damage mechanisms capable of significant reduction in effective permeability (sometimes near 100%). In this study, a new chemical treatment is proposed for efficient remediation of water- or hydrocarbon-phase-trapping damage in low-permeability porous media. The method proposed here is cost-effective and experimentally proved to be efficient and long-lasting. Such a chemical treatment is recommended to alleviate gas flow in tight gas with aqueous-trapping-damaged zones or in gas condensate reservoirs with condensate-banking challenges. Introduction Remediation techniques for existing aqueous- or hydrocarbon-phase-trapping damage can be categorized into two approaches: bypassing the damaged region by direct penetration techniques and trapping-phase removal. In the former category, the damaged zone is bypassed by creation of high-conductance flow paths through hydraulic fracturing or acidizing. However, for tight and ultratight formations, conventional acidizing may not be feasible (mostly because of injectivity difficulties). In the second category, direct removal and indirect removal have been used, but usually are seen as short-term solutions. The fluid used in the proposed treatment is comprised of a nonacidic chelating agent. The treatment fluid can be injected safely into the damaged region, while a slow reaction rate allows it to penetrate deep into the formation. In the proposed treatment, the mechanism is the permanent enlargement of pore throats where the nonwetting phase has the most restriction (to overcome the capillary forces) to pass through. In fact, phase trapping or capillary trapping occurs inside the pore structure when viscous forces are not strong enough to overcome the capillary pressure. The experimental setup and method are detailed in the complete paper. Results and Discussion Treatment of Outcrop Samples: Lueder Carbonate. The performance of the proposed treatment fluid initially was investigated on two outcrop core samples from the Lueder carbonate formation. The first treatment was conducted on the Le1 core sample with an absolute permeability of 1.46 md. To establish trapped water in the core, 10 pore volumes (PV) of 5 wt% potassium chloride brine were injected followed by nitrogen (N2) gas displacement. Then, to achieve irreducible water saturation, N2 was injected at a rate of 2 cm3/min for at least 100 PVs until no further water was produced. Next, the effective gas permeability was measured while N2 was injected at approximately 0.2 cm3/min. The effective gas permeability was obtained as 0.042 md. The trapped water saturation was also calculated (from the core weight) as 77.7%. After all pretreatment measurements, the core was loaded into the core holder for the treatment. The treatment injections with preflush and post-flush were performed at 130°C. In this test, 0.5 PV of treatment fluid was injected.
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Sadooni, Mostafa, and Ashkan Zonnouri. "The Effect of Nitrogen Injection on Production Improvement in an Iranian Rich Gas Condensate Reservoir." Petroleum Science and Technology 33, no. 4 (February 3, 2015): 422–29. http://dx.doi.org/10.1080/10916466.2014.992535.
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Rahmanifard, H., A. Helalizadeh, M. Ebrahimi, A. M. Shabibasl, and N. Mayahi. "Field scale and economical analysis of carbon dioxide, nitrogen, and lean gas injection scenarios in Pazanan gas condensate reservoir." International Journal of Petroleum Engineering 1, no. 1 (2014): 62. http://dx.doi.org/10.1504/ijpe.2014.059422.
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Hagoort, J., J. W. Brinkhorst, and Piet H. van der Kleyn. "Development of an Offshore Gas Condensate Reservoir by Nitrogen Injection vs. Pressure Depletion (includes associated paper 18560 )." Journal of Petroleum Technology 40, no. 04 (April 1, 1988): 463–69. http://dx.doi.org/10.2118/15873-pa.
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Boreham, C. J., and R. A. de Boer. "ORIGIN OF GILMORE GAS AND OIL, ADAVALE BASIN, CENTRAL QUEENSLAND." APPEA Journal 38, no. 1 (1998): 399. http://dx.doi.org/10.1071/aj97019.
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Dry gas in the Gilmore Field of the Adavale Basin has been sourced from both wet gas associated with oil generation, together with methane from a deep, overmature source. The latter gas input is further characterised by a high nitrogen content co-generated with isotopically heavy methane and carbon dioxide. The eastern margin of the Lissoy Sandstone principal reservoir unit contains the higher content of overmature dry gas supporting reservoir compiirtmenmlisalion and a more favourable migration pathway to this region. The combination of a molecular and multi-element isotopic approach is an effective tool for the recognition of an overmature, dry gas source. This deep source represents a play concept that previously has been undervalued and may be more widespread within Australian sedimentary basins.The maturity level of the wet gas and associated oil are identical, having reached an equivalent vitrinite reflectance of 1.4−1.6 per cent. Modelling studies support the concept of local Devonian source rocks for the wet gas and oil. Reservoir filling from late stage, high maturity oil and gas generation and expulsion, was a result of reactivation of petroleum generation from Devonian source rocks during the Early Cretaceous. The large input of dry gas from a deeper and highly overmature source is a more recent event. This gas can fractionally displace condensable C2+ liquids already in the reservoir possibly allowing tertiary migration into younger reservoirs, or adjacent structures.Oil recovered from Gilmore-2 has been sourced from Devonian marine organic matter, deposited under mildly evaporitic, restricted marine conditions. The most likely source rocks in the Adavale Basin are the basal marine shale of the Log Creek Formation, algal shales at the top of the Lissoy Sandstone, and the Cooladdi Dolomite. Source-sensitive biomarkers and carbon isotope composition of the Gilmore-2 oil have much in common with other Devonian-sourced oils from the Bonaparte and Canning basins. The chemical link between western and eastern Australian Devonian oils may suggest diachronous development of source rocks over a wide extent. This implies that the source element of the Devonian Petroleum Supersystem may be present in other sedimentary basins.
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Hoteit, Hussein, and Abbas Firoozabadi. "Compositional Modeling of Discrete-Fractured Media Without Transfer Functions by the Discontinuous Galerkin and Mixed Methods." SPE Journal 11, no. 03 (September 1, 2006): 341–52. http://dx.doi.org/10.2118/90277-pa.
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Summary In a recent work, we introduced a numerical approach that combines the mixed-finite-element (MFE) and the discontinuous Galerkin (DG) methods for compositional modeling in homogeneous and heterogeneous porous media. In this work, we extend our numerical approach to 2D fractured media. We use the discrete-fracture model (crossflow equilibrium) to approximate the two-phase flow with mass transfer in fractured media. The discrete-fracture model is numerically superior to the single-porosity model and overcomes limitations of the dual-porosity model including the use of a shape factor. The MFE method is used to solve the pressure equation where the concept of total velocity is invoked. The DG method associated with a slope limiter is used to approximate the species-balance equations. The cell-based finite-volume schemes that are adapted to a discrete-fracture model have deficiency in computing the fracture/fracture fluxes across three and higher intersecting-fracture branches. In our work, the problem is solved definitively because of the MFE formulation. Several numerical examples in fractured media are presented to demonstrate the superiority of our approach to the classical finite-difference method. Introduction Compositional modeling in fractured media has broad applications in CO2, nitrogen, and hydrocarbon-gas injection, and recycling in gas condensate reservoirs. In addition to species transfer, the compressibility effects should be also considered for such applications. Heterogeneities and fractures add complexity to the fluid-flow modeling. Several conceptually different models have been proposed in the literature for the simulation of flow and transport in fractured porous media. The single-porosity approach uses an explicit computational representation for fractures (Ghorayeb and Firoozabadi 2000; Rivière et al. 2000). It allows the geological parameters to vary sharply between the matrix and the fractures. However, the high contrast and different length scales in the matrix and fractures make the approach unpractical because of the ill conditionality of the matrix appearing in the numerical computations (Ghorayeb and Firoozabadi 2000).The small control volumes in the fracture grids also add a severe restriction on the timestep size because of the Courant-Freidricks-Levy (CFL) condition if an explicit temporal scheme is used.
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Narayanaswamy, Ganesh, Mukul M. Sharma, and G. A. Pope. "Effect of Heterogeneity on the Non-Darcy Flow Coefficient." SPE Reservoir Evaluation & Engineering 2, no. 03 (June 1, 1999): 296–302. http://dx.doi.org/10.2118/56881-pa.
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Summary An analytical method for calculating an effective non-Darcy flow coefficient for a heterogeneous formation is presented. The method presented here can be used to calculate an effective non-Darcy flow coefficient for heterogeneous gridblocks in reservoir simulators. Based on this method, it is shown that the non-Darcy flow coefficient of a heterogeneous formation is larger than the non-Darcy flow coefficient of an equivalent homogenous formation. Non-Darcy flow coefficients calculated from gas well data show that non-Darcy flow coefficients obtained from well tests are significantly larger than those predicted from experimental correlations. Permeability heterogeneity is a very likely reason for the differences in non-Darcy flow coefficients often seen between laboratory and field data. Introduction In this paper, we present an analytical method for calculating an effective non-Darcy flow coefficient for a heterogeneous reservoir. The effect of heterogeneity on the non-Darcy flow coefficient is also shown using numerical simulations. Non-Darcy flow coefficients calculated from the analysis of welltest data from a gas condensate field are compared with experimental correlations. Such a comparison allows us to more accurately assess the importance of non-Darcy flow in gas condensate reservoirs. Literature Review As early as 1901, Reynolds observed, in his classical experiments of injecting dye into water flowing through glass tubes, that after some high flowrate, flow rate was no longer proportional to the pressure drop. Forchheimer1 also observed this phenomena and proposed the following quadratic equation to express the relationship between pressure drop and velocity in a porous medium: d P d r = μ k u + β ρ u 2 . ( 1 ) This equation has come to be known asForchheimer's equation. At low Reynolds number (creeping flow conditions), the above equation reduces to Darcy's law. Tek2 developed a generalized Darcy equation in dimensionless form which predicts the pressure drop with good agreement over all ranges of Reynolds numbers. Katz et al.3 attributed the phenomenon of non-Darcy flow to turbulence. Tek et al.4 proposed the following correlation for?: β = 5.5 × 10 9 k 5 / 4 ϕ 3 / 4 . ( 2 ) Gewers and Nichol5 conducted experiments on microvugular carbonate cores to measure the non-Darcy flow coefficient. They also studied the effect of the presence of a second static fluid phase and the effect on plugging due to fines migration. They found that ? decreases and then increases with liquid saturation. Wong6 studied the effect of a mobile liquid saturation on ?. He used distilled water as the liquid phase and water saturated nitrogen as the gas phase on the same cores used by Gewers and Nichol. He plotted ? vs liquid saturation and found that there is an eight-fold increase in ? when the liquid saturation increases from 40% to 70%. He concluded that ? can be approximately calculated from the dry core experiments by using the effective gas permeability. Geertsma7,8 introduced an empirical relationship between ?,k and ? based on a combination of experimental data and dimensional analysis. He noted that the observed departure from Darcy's law was due to the convective acceleration and deceleration of the fluid particles. He also defined a new Reynolds number as ?k??/?, and suggested the following correlation for ? with a constant C (k is in ft 2, ?is in 1/ft). β = C k 0.5 ϕ 5.5 . ( 3 ) For the case of gas flowing through a core with a static liquid phase, he suggested the following correlation: β = C ( k k r g ) 0.5 [ ϕ ( 1 − S w ) ] 5.5 . ( 4 ) Phipps and Khalil9 proposed a method for determining the exponent in a Forchheimer-type equation. Firoozabadi and Katz10 presented are view of the theory of high velocity gas flow through porous media. Evanset al.11 reviewed the various correlations. They conducted an experimental study of the effect of the immobile liquid saturation and suggested a correlation based on dimensional analysis. Nguyen12performed an experimental study of non-Darcy flow through perforations on a synthetic core using air. These experiments showed that non-Darcy flow exists in the convergence zone and the perforation tunnel. Results of this study showed that Darcy flow equations can over predict well productivity by as much as 100%. Jones13 conducted experiments on 355 sandstone and 29 limestone cores. These tests were done for various core types: vuggy limestones, crystalline limestones, and fine grained sandstones. He presented the following correlation: β = 6.15 × 10 10 k − 1.55 . ( 5 ) He also points out that the group ?k? which is the characteristic length used for defining a Reynolds number for porous media, should be proportional to the characteristic length k/ϕ. He developed an approximate multilayer flow model that demonstrates that the departure from the above relation is due to permeability variations. Jones suggested that heterogeneity may be the reason why all correlations involving ? exhibit so much scatter.
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Fishlock, T. P., and C. J. Probert. "Waterflooding of Gas Condensate Reservoirs." SPE Reservoir Engineering 11, no. 04 (November 1, 1996): 245–51. http://dx.doi.org/10.2118/35370-pa.
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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 (December 24, 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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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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Bybee, Karen. "Well Productivity in Gas/Condensate Reservoirs." Journal of Petroleum Technology 52, no. 04 (April 1, 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 (August 1, 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 (April 1, 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 (December 1, 1989): 576–84. http://dx.doi.org/10.2118/16984-pa.
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Bybee, Karen. "Well Test Analysis in Gas/Condensate Reservoirs." Journal of Petroleum Technology 52, no. 11 (November 1, 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 (August 1, 1988): 1049–56. http://dx.doi.org/10.2118/15875-pa.
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Shams, Bilal, Jun Yao, Kai Zhang, and Lei Zhang. "Sensitivity analysis and economic optimization studies of inverted five-spot gas cycling in gas condensate reservoir." Open Physics 15, no. 1 (August 3, 2017): 525–35. http://dx.doi.org/10.1515/phys-2017-0060.
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AbstractGas condensate reservoirs usually exhibit complex flow behaviors because of propagation response of pressure drop from the wellbore into the reservoir. When reservoir pressure drops below the dew point in two phase flow of gas and condensate, the accumulation of large condensate amount occurs in the gas condensate reservoirs. Usually, the saturation of condensate accumulation in volumetric gas condensate reservoirs is lower than the critical condensate saturation that causes trapping of large amount of condensate in reservoir pores. Trapped condensate often is lost due to condensate accumulation-condensate blockage courtesy of high molecular weight, heavy condensate residue. Recovering lost condensate most economically and optimally has always been a challenging goal. Thus, gas cycling is applied to alleviate such a drastic loss in resources.In gas injection, the flooding pattern, injection timing and injection duration are key parameters to study an efficient EOR scenario in order to recover lost condensate. This work contains sensitivity analysis on different parameters to generate an accurate investigation about the effects on performance of different injection scenarios in homogeneous gas condensate system. In this paper, starting time of gas cycling and injection period are the parameters used to influence condensate recovery of a five-spot well pattern which has an injection pressure constraint of 3000 psi and production wells are constraint at 500 psi min. BHP. Starting injection times of 1 month, 4 months and 9 months after natural depletion areapplied in the first study. The second study is conducted by varying injection duration. Three durations are selected: 100 days, 400 days and 900 days.In miscible gas injection, miscibility and vaporization of condensate by injected gas is more efficient mechanism for condensate recovery. From this study, it is proven that the application of gas cycling on five-spot well pattern greatly enhances condensate recovery preventing financial, economic and resource loss that previously occurred.
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Lopez Jimenez, Bruno A., and Roberto Aguilera. "Flow Units in Shale Condensate Reservoirs." SPE Reservoir Evaluation & Engineering 19, no. 03 (April 13, 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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Bilotu Onoabhagbe, Benedicta, Paul Russell, Johnson Ugwu, and Sina Rezaei Gomari. "Application of Phase Change Tracking Approach in Predicting Condensate Blockage in Tight, Low, and High Permeability Reservoirs." Energies 13, no. 24 (December 11, 2020): 6551. http://dx.doi.org/10.3390/en13246551.
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Prediction of the timing and location of condensate build-up around the wellbore in gas condensate reservoirs is essential for the selection of appropriate methods for condensate recovery from these challenging reservoirs. The present work focuses on the use of a novel phase change tracking approach in monitoring the formation of condensate blockage in a gas condensate reservoir. The procedure entails the simulation of tight, low and high permeability reservoirs using global and local grid analysis in determining the size and timing of three common regions (Region 1, near wellbore; Region 2, condensate build-up; and Region 3, single-phase gas) associated with single and two-phase gas and immobile and mobile gas condensate. The results show that permeability has a significant influence on the occurrence of the three regions around the well, which in turn affects the productivity of the gas condensate reservoir studied. Predictions of the timing and location of condensate in reservoirs with different permeability levels of 1 mD to 100 mD indicate that local damage enhances condensate formation by 60% and shortens the duration of the immobile phase by 45%. Meanwhile, the global change in permeability increases condensate formation by 80% and reduces the presence of the immobile phase by 60%. Finally, this predictive approach can help in mitigating condensate blockage around the wellbore during production.
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Ahmadi, Mohammad Ali, Mohammad Ebadi, Payam Soleimani Marghmaleki, and Mohammad Mahboubi Fouladi. "Evolving predictive model to determine condensate-to-gas ratio in retrograded condensate gas reservoirs." Fuel 124 (May 2014): 241–57. http://dx.doi.org/10.1016/j.fuel.2014.01.073.
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Regueiro, José, and Andrés Peña. "AVO in North of Paria, Venezuela: Gas methane versus condensate reservoirs." GEOPHYSICS 61, no. 4 (July 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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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 (May 18, 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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Denney, Dennis. "Multiphase Transient Well Testing for Gas-Condensate Reservoirs." Journal of Petroleum Technology 49, no. 11 (November 1, 1997): 1251–53. http://dx.doi.org/10.2118/1197-1251-jpt.
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Behmanesh, Hamid, Hamidreza Hamdi, and Christopher R. Clarkson. "Production data analysis of tight gas condensate reservoirs." Journal of Natural Gas Science and Engineering 22 (January 2015): 22–34. http://dx.doi.org/10.1016/j.jngse.2014.11.005.
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Ahmadi, M., M. Sharifi, and A. Hashemi. "Comparison of Simulation Methods in Gas Condensate Reservoirs." Petroleum Science and Technology 32, no. 7 (February 14, 2014): 761–71. http://dx.doi.org/10.1080/10916466.2011.604063.
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Zheng, Shi-Yi, Murat Zhiyenkulov, and TongChun Yi. "Productivity evaluation of hydraulically fractured gas-condensate reservoirs." Petroleum Geoscience 12, no. 3 (August 2006): 275–84. http://dx.doi.org/10.1144/1354-079304-644.
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Qassamipour, M., and A. Hashemi. "Mechanisms of Liquid Buildup in Gas Condensate Reservoirs." Petroleum Science and Technology 29, no. 23 (October 18, 2011): 2425–31. http://dx.doi.org/10.1080/10916461003699168.
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App, J. F., and K. K. Mohanty. "Relative Permeability Estimation for Rich Gas-Condensate Reservoirs." Transport in Porous Media 58, no. 3 (March 2005): 287–313. http://dx.doi.org/10.1007/s11242-004-1407-5.
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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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Chen, H. L., S. D. Wilson, and T. G. Monger-McClure. "Determination of Relative Permeability and Recovery for North Sea Gas-Condensate Reservoirs." SPE Reservoir Evaluation & Engineering 2, no. 04 (August 1, 1999): 393–402. http://dx.doi.org/10.2118/57596-pa.
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Summary Coreflood experiments on gas condensate flow behavior were conducted for two North Sea gas condensate reservoirs. The objectives were to investigate the effects of rock and fluid characteristics on critical condensate saturation (CCS), gas and condensate relative permeabilities, hydrocarbon recovery and trapping by water injection, and incremental recovery by subsequent blowdown. Both CCS and relative permeability were sensitive to flow rate and interfacial tension. The results on gas relative permeability rate sensitivity suggest that gas productivity curtailed by condensate dropout can be somewhat restored by increasing production rate. High interfacial tension ultimately caused condensate relative permeability to decrease with increasing condensate saturation. Condensate immobile under gas injection could be recovered by water injection, but more immediate and efficient condensate recovery was observed when the condensate saturation prior to water injection exceeded the CCS. Subsequent blowdown recovered additional gas, but incremental condensate recovery was insignificant. Introduction Reservoirs bearing gas condensates are becoming more commonplace as developments are encountering greater depths, higher pressures, and higher temperatures. In the North Sea, gas condensate reservoirs comprise a significant portion of the total hydrocarbon reserves. Accuracy in engineering computations for gas condensate systems (e.g., estimating reserves, sizing surface facilities, and predicting productivity trends) depends upon a basic understanding of phase and flow behavior interrelationships. For example, gas productivity may be curtailed as condensate accumulates by pressure depletion below the dew point pressure (Pd). Conceptual modeling on gas condensate systems suggests that relative permeability (kr) curves govern the magnitude of gas productivity loss.1,2 Unfortunately, available gas and condensate relative permeability (krg and krc) results for gas condensates are primarily limited to synthetic systems. Such results show that higher CCS and less krg reduction were observed for a conventional gas/oil system compared to a gas condensate system.3,4 If condensate accumulates as a continuous film due to low interfacial tension (IFT), then high IFT gas/oil and water/oil kr data may not be applicable to gas condensates.5 Water invasion of gas condensate reservoirs may enhance hydrocarbon recovery or trap potential reserves. Laboratory results suggest water invasion of low IFT gas condensates may not be represented using high IFT water/oil and water/gas displacements.6 Subsequent blowdown may remobilize hydrocarbons trapped by water invasion. The presence of condensate may hinder gas remobilization, thus conventional gas/water blowdown experiments may not be appropriate in evaluating the feasibility of depressurization for gas condensates.7,8 Other laboratory evaluations of gas condensate flow behavior indicate measured results depend upon experimental procedures, fluid properties, and rock properties.3,9–20 Factors to consider include the history of condensate formation (i.e., imbibition or drainage), how condensate was introduced (i.e., in-situ dropout versus external injection or inflowing gas), flow rate, differential pressure, system pressure, IFT, connate water saturation, core permeability, and core orientation. Experiments performed to evaluate the consequences of water invasion suggest optimum conditions depend upon IFT, initial gas saturation, and core permeability.7,21,22 Reported blowdown experiments imply gas recovery depends upon the degree of gas expansion.7,8 The kr results obtained in this study represent gas condensate flow between the far-field and the near-wellbore region. The results are useful input for numerical simulation, especially to test rate- or IFT-sensitive relative permeability functions. Results on hydrocarbon recovery and trapping from water injection and blowdown are beneficial in evaluating improved recovery options for gas condensates. Experimental Procedures Coreflooding experiments were performed under reservoir conditions using rock and fluid samples from two distinct North Sea gas condensate reservoirs. A detailed description of the experimental methods is provided in the Appendix. Briefly, the experiments were conducted in a horizontal coreflood apparatus equipped with in-line PVT and viscosity measuring devices. The entire system experienced in-situ condensate drop out by constant volume depletion (CVD) from above Pd to either the pressure corresponding to CCS, or to the pressure of maximum condensate saturation Scmax Steady-state krg was measured by injecting equilibrated gas (before CCS). Steady-state krg and krc were measured by injecting gas condensate repressurized to above Pd (after CCS). The gas/oil fractional flow rate was defined by the pressure level in the core which was controlled by the core outlet back-pressure regulator. During krg measurements, the injection rate was varied to access rate effects. After the krg or krg and krc measurements to Scmax were completed, water injection was performed to quantify hydrocarbon trapping and recovery. Blowdown followed to evaluate additional hydrocarbon recovery. Recombined Reservoir Fluid Properties. Two North Sea gas condensate reservoir fluids were recombined using separator oil and synthetic gas. Tables 1 and 2 list compositions and PVT properties for the reconstituted fluids. The Pd was 7,070 psig at 250°F for Reservoir A, and 6,074 psig at 259°F for Reservoir B (Table 2). The maximum liquid dropout under constant composition expansion (CCE) was 31.7% for Reservoir A, and 42.5% for Reservoir B (Fig. 1). Reservoir B is a richer gas condensate and exhibits more near-critical phase behavior than Reservoir A.
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Denney, Dennis. "Application of Horizontal Wells To Reduce Condensate Blockage in Gas/Condensate Reservoirs." Journal of Petroleum Technology 62, no. 11 (November 1, 2010): 78–80. http://dx.doi.org/10.2118/1110-0078-jpt.
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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 (April 14, 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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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 (December 1, 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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Denney, Dennis. "Well-Test Dynamics in Rich-Gas/Condensate Reservoirs Under Gas Injection." Journal of Petroleum Technology 62, no. 02 (February 1, 2010): 69–71. http://dx.doi.org/10.2118/0210-0069-jpt.
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Zhu, Weiyao, Kun Huang, Yan Sun, Jing Xia, and Ming Yue. "Theoretical study on the injected gas override in condensate gas reservoirs." Fuel 266 (April 2020): 116977. http://dx.doi.org/10.1016/j.fuel.2019.116977.
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Meng, Xingbang, James J. Sheng, and Yang Yu. "Experimental and Numerical Study of Enhanced Condensate Recovery by Gas Injection in Shale Gas-Condensate Reservoirs." SPE Reservoir Evaluation & Engineering 20, no. 02 (May 1, 2017): 471–77. http://dx.doi.org/10.2118/183645-pa.
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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 (December 1, 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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Wang, Xiuli, and K. K. Mohanty. "Pore-Network Model of Flow in Gas/Condensate Reservoirs." SPE Journal 5, no. 04 (December 1, 2000): 426–34. http://dx.doi.org/10.2118/67857-pa.
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Cikes, Marin, and Michael J. Economides. "Fracturing of High-Temperature, Naturally Fissured, Gas-Condensate Reservoirs." SPE Production Engineering 7, no. 02 (May 1, 1992): 226–32. http://dx.doi.org/10.2118/20973-pa.
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Petrosov, M. Yu, A. Yu Lomukhin, S. V. Romashkin, and O. Yu Kulyatin. "Intellectualization and digitalization for low-permeability gas-condensate reservoirs." Neftyanoe khozyaystvo - Oil Industry, no. 7 (2019): 108–13. http://dx.doi.org/10.24887/0028-2448-2019-7-108-113.
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