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Academic literature on the topic 'Gas condensate reservoirs. Nitrogen'

Author: Grafiati

Published: 4 June 2021

Last updated: 10 February 2022

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Journal articles on the topic "Gas condensate reservoirs. Nitrogen"

1

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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2

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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3

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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Dissertations / Theses on the topic "Gas condensate reservoirs. Nitrogen"

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Ouzzane, Djamel Eddine. "Phase behaviour in gas condensate reservoirs." Thesis, Imperial College London, 2005. http://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.417922.

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

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

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Vo, Dyung Tien. "Well test analysis for gas condensate reservoirs /." Access abstract and link to full text, 1989. http://0-wwwlib.umi.com.library.utulsa.edu/dissertations/fullcit/9014121.

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

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

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Del, Castillo Maravi Yanil. "New inflow performance relationships for gas condensate reservoirs." Texas A&M University, 2003. http://hdl.handle.net/1969/354.

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

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Saleh, Amer Mohamed. "Well test and production prediction of gas condensate reservoirs." Thesis, Heriot-Watt University, 1992. http://hdl.handle.net/10399/813.

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Daltaban, T. S. "Numerical modelling of recovery processes from gas condensate reservoirs." Thesis, Imperial College London, 1986. http://hdl.handle.net/10044/1/37987.

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Adeyeye, Adedeji Ayoola. "Gas condensate damage in hydraulically fractured wells." Texas A&M University, 2003. http://hdl.handle.net/1969.1/213.

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This project is a research into the effect of gas condensate damage in hydraulically fractured wells. It is the result of a problem encountered in producing a low permeability formation from a well in South Texas owned by the El Paso Production Company. The well was producing a gas condensate reservoir and questions were raised about how much drop in flowing bottomhole pressure below dewpoint would be appropriate. Condensate damage in the hydraulic fracture was expected to be of significant effect. Previous attempts to answer these questions have been from the perspective of a radial model. Condensate builds up in the reservoir as the reservoir pressure drops below the dewpoint pressure. As a result, the gas moving to the wellbore becomes leaner. With respect to the study by El-Banbi and McCain, the gas production rate may stabilize, or possibly increase, after the period of initial decline. This is controlled primarily by the condensate saturation near the wellbore. This current work has a totally different approach. The effects of reservoir depletion are minimized by introduction of an injector well with fluid composition the same as the original reservoir fluid. It also assumes an infinite conductivity hydraulic fracture and uses a linear model. During the research, gas condensate simulations were performed using a commercial simulator (CMG). The results of this research are a step forward in helping to improve the management of gas condensate reservoirs by understanding the mechanics of liquid build-up. It also provides methodology for quantifying the condensate damage that impairs linear flow of gas into the hydraulic fracture.

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10

Almusabeh, Muzher I. "Predicting the gas-condensate extended composition analysis." Morgantown, W. Va. : [West Virginia University Libraries], 2010. http://hdl.handle.net/10450/11076.

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Thesis (M.S.)--West Virginia University, 2010.
Title from document title page. Document formatted into pages; contains ix, 52 p. : ill. (some col.). Includes abstract. Includes bibliographical references (p. 49-51).

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Books on the topic "Gas condensate reservoirs. Nitrogen"

1

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

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

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

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

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

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

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

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

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

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

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Book chapters on the topic "Gas condensate reservoirs. Nitrogen"

1

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

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

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Ahmadi, M. A., and A. Bahadori. "Retrograde Gas Condensate." In Fluid Phase Behavior for Conventional and Unconventional Oil and Gas Reservoirs, 333–404. Elsevier, 2017. http://dx.doi.org/10.1016/b978-0-12-803437-8.00007-5.

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Sheng, James J. "Huff-n-puff injection in shale gas condensate reservoirs." In Enhanced Oil Recovery in Shale and Tight Reservoirs, 81–115. Elsevier, 2020. http://dx.doi.org/10.1016/b978-0-12-815905-7.00004-9.

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Conference papers on the topic "Gas condensate reservoirs. Nitrogen"

1

Sänger, P. J., H. K. Bjørnstad, and Jacques Hagoort. "Nitrogen Injection Into Stratified Gas-Condensate Reservoirs." In SPE Annual Technical Conference and Exhibition. Society of Petroleum Engineers, 1994. http://dx.doi.org/10.2118/28941-ms.

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Siregar, S., J. Hagoort, and H. Ronde. "Nitrogen Injection vs. Gas Cycling in Rich Retrograde Condensate-Gas Reservoirs." In International Meeting on Petroleum Engineering. Society of Petroleum Engineers, 1992. http://dx.doi.org/10.2118/22360-ms.

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3

Taha, Maged Alaa, Eissa Shokier, Attia Attia, Aamer Yahia, and Khaled Mansour. "Enhancing Hydrocarbon Production Through Thermal Gas Injection from a Retrograde as Condensate Reservoir in the Western Desert in Egypt." In SPE Annual Technical Conference and Exhibition. SPE, 2021. http://dx.doi.org/10.2118/206190-ms.

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Abstract In retrograde gas condensate reservoirs, condensate blockage is a major reservoir damage problem, where liquid is dropped-out of natural gas, below dew-point pressure. Despite that most of this liquid will not produce due to not reaching the critical saturation, natural gas will be blocked by the accumulated liquid and will also not produce. This work investigates the effects of gas injection (such as methane, carbon-dioxide, and nitrogen) and steam at high temperatures on one of the Egyptian retrograde gas condensate reservoirs. Several gas injection scenarios that comprise different combination of gas injection temperature, enthalpy, injection gas types (CO2, N2, and CH4), and injection-rates were carried out. The results indicated that all conventional and thermal gas injection scenarios do not increase the cumulative gas production more than the depletion case. The non-thermal gas injection scenarios increased the cumulative condensate production by 8.6%. However, thermal CO2 injection increased the condensate production cumulative by 28.9%. It was observed that thermal gas injection does not vaporize condensate It was observed that thermal gas injection does not vaporize condensate more than conventional injection that have the same reservoir pressure trend. However, thermal injection mainly improves the condensate mobility. Appropriately, thermal injection in retrograde reservoirs, is mostly applicable for depleted reservoirs when the largest amount of non-producible liquid is already dropped out. Finally, this research studied executing thermal gas injection in retrograde gas condensate reservoirs, operationally, by considering the following items: carbon dioxide recovery unit, compressors, storage-tanks, anti-corrosion pipe-lines and tubing-strings, and corrosion-inhibitors along with downhole gas heaters.

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Canchucaja, Ramiro, and Manuel Sueiro. "Feasibility of Nitrogen Injection in a Multi-layered Lean Gas Condensate Reservoir." In SPE Russian Petroleum Technology Conference. Society of Petroleum Engineers, 2018. http://dx.doi.org/10.2118/191652-18rptc-ms.

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Linderman, John Thomas, Faisal Salah Al-Jenaibi, Saleem G. Ghori, Kevin Putney, John Lawrence, Michel Gallat, and Kurt Hohensee. "Feasibility Study Of Substituting Nitrogen For Hydrocarbon In A Gas Recycle Condensate Reservoir." In Abu Dhabi International Petroleum Exhibition and Conference. Society of Petroleum Engineers, 2008. http://dx.doi.org/10.2118/117952-ms.

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Canchucaja, Ramiro, and Manuel Sueiro. "Feasibility of Nitrogen Injection in a Multi-layered Lean Gas Condensate Reservoir (Russian)." In SPE Russian Petroleum Technology Conference. Society of Petroleum Engineers, 2018. http://dx.doi.org/10.2118/191652-18rptc-ru.

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Abdulwahab, Haytham, and Hadi Belhaj. "Managing the Breakthrough of Injected Nitrogen at a Gas Condensate Reservoir in Abu Dhabi." In Abu Dhabi International Petroleum Exhibition and Conference. Society of Petroleum Engineers, 2010. http://dx.doi.org/10.2118/137330-ms.

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Hamza, Hamza M., Mahmood Al Suwaidi, Omar Al Jeelani, Arafat Al Yafei, Mahmoud Basioni, Khaled Al Yaqoubi, and Arun Kumar. "A Case History of Nitrogen Injection Monitoring in Rich Recycled Gas Condensate Reservoir, Onshore Gas Field, Abu Dhabi, UAE." In Abu Dhabi International Petroleum Exhibition and Conference. Society of Petroleum Engineers, 2015. http://dx.doi.org/10.2118/177790-ms.

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Ladmia, Abdelhak, Martin Culen, Abdulla Bakheet Al Katheeri, Fahad Mustfa Ahmed Al Hosani, Graham F. J. Edmonstone, Alfonso Mantilla, Mohamed Ahmed Baslaib, et al. "Case Study of Underbalance Coiled Tubing Drilling to Increase Well Productivity and Ultimate Recovery in Tight Gas Reservoir Onshore Field, Abu Dhabi." In SPE/ICoTA Well Intervention Conference and Exhibition. SPE, 2021. http://dx.doi.org/10.2118/204436-ms.

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Abstract Coiled Tubing Drilling (CTD) has been growing and developed rapidly through the last two decades. There have been numerous highly successful applications of CTD technology in Alaska, Canada, Oman and the United Arab Emirates (Sharjah Sajaa and Dubai Murgham fields), among other places. Currently, Saudi Arabia has undertaken a campaign for the last seven years that has shown successful results in gas reservoirs. ADNOC initiated a trial Coiled Tubing Underbalanced Drilling (CTUBD) project in the onshore tight gas reservoirs in Abu Dhabi, United Arab Emirates beginning operations 1-December-2019. The initial trial will consist of three (3) wells. The purpose of the trial is to assess the suitability of CTUBD for drilling the reservoir sections of wells in these fields, and further application in others. The reason for choosing coiled tubing for drilling the reservoir sections is based upon the high H2S content of the reservoir fluids and the premise that HSE can be enhanced by using a closed drilling system rather than an open conventional system. The three wells will be newly drilled, cased and cemented down to top reservoir by a conventional rig. The rig will run the completion and Christmas tree before moving off and allowing the coiled tubing rig to move onto the well. The coiled tubing BOPs will be rigged up on top of the Christmas tree and a drilling BHA will be deployed through the completion to drill the reservoir lateral. The wells will be drilled underbalanced to aid reservoir performance and to allow hole cleaning with returns being taken up the coiled tubing / tubing annulus. The returns will be routed to a closed separation system with produced gas and condensate being primarily exported to the field plant via the production line, solids sparge to a closed tank or pit and the drilling fluid re-circulated. The primary drilling fluid will be treated water; however, nitrogen may be required for drilling future wells in the field and will be required regardless for purging gas from the surface equipment during operations. A flare will also be required for emergency use and for start-up of drilling. If the trial proves a success, a continuous drilling plan will be put in place.

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Pan, Lijuan, Huifeng Liu, Wu Long, Jiaxue Li, Jianbo Li, and Qi Liu. "A Novel Foamy Well Killing Fluid for Low-Pressure Gas Reservoirs in Tarim Basin, China." In International Petroleum Technology Conference. IPTC, 2021. http://dx.doi.org/10.2523/iptc-21434-ms.

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Abstract Many mature gas reservoirs in China have very low formation pressure, like Yakela, Dalaoba, Kekeya etc. The formation pressure coefficient ranges from 0.6 to 0.9. Conventional well killing fluids easily leak into the formation and damage the well productivity. There are alternative well killing fluids in the industry to kill low-pressure formations, including foamy fluid, oil-based emulsion fluid and well killing fluid with density reducing agent. However, the densities of these alternative well killing fluids are mostly higher than 0.8 g/cm3, and the cost is high if large volume of density reducing agent is used to decrease the density to lower than 0.8 g/cm3. In this paper, a formula of nitrogen foamy well killing fluid is developed and successfully used in sand removal operations in low-pressure gas reservoirs. A series of tests are conducted to select the optimal foaming agent, foam stabilizer and other additives. Sodium dodecyl sulfate is selected as the foaming agent. However, the properties of Sodium dodecyl sulfate are not stable in hard water, so we use dodecyl dimethyl betaine with sodium dodecyl sulfate together to increase the foaming ability in tough water environment like in the desert area. Xanthan gum is selected as a foam stabilizer because it can thicken the fluid phase and reduce the drainage speed. Gelatin is also added into the formula because it can form stable coacervate with xanthan gum. The concentration of each additive is also optimized through lots of tests. Then the properties of the foamy well killing fluid are tested. Its density is between 0.50-0.80 g/cm3 and is adjustable. Under the temperature of 150°C, its plastic viscosity is 51mPa.s; its yield point is 51.5 Pa; the half-life period reaches 3055min. These basic properties meet the requirements of being used as well killing fluid. Salinity tolerance and oil resistance tests are also conducted to see the toughest environment that the fluid can be used in. The results show that the formula can be used in the oilfield where the water salinity is less than 100000 mg/L and the oil content is less than 15%. A model of calculating the equivalent density of the foam is developed. Scenarios of field application and onsite maintenance are also established. If a completion operation or a workover operation lasts for more than 24 hours, the foamy fluid needs to be maintained every day to guarantee its performance in the wellbore. The newly formulated well killing fluid has been used in three wells in Yakela condensate gas filed in Tarim Basin, western China, where the formation pressure coefficient is 0.67 and the formation is strongly water sensitive. A foamy well killing fluid density of 0.72g/cm3 was used (surface density 0.53 g/cm3) for the sand removal operation in well Ya2-2-4. No fluid loss has been observed during the whole operational process. Neither gas seepage nor oil overflow has been observed during well killing. The well has recovered from production after workover and the production rate reaches 90×103m3 natural gas with 12t condensate oil every day. The new formula of foamy well killing fluid not only shows good laboratory properties under 150°C, but also proves to be a good solution to the downhole operations in low-pressure and depleted reservoirs.

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Reports on the topic "Gas condensate reservoirs. Nitrogen"

1

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

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Oldenburg, Curtis M., George J. Moridis, Nicholas Spycher, and Karsten Pruess. EOS7C Version 1.0: TOUGH2 Module for Carbon Dioxide or Nitrogen inNatural Gas (Methane) Reservoirs. Office of Scientific and Technical Information (OSTI), June 2004. http://dx.doi.org/10.2172/878525.

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Wolcott, Joanne, and Sara Shayegi. Improved Recovery from Gulf of Mexico Reservoirs, Volume 4, Comparison of Methane, Nitrogen and Flue Gas for Attic Oil. February 14, 1995 - October 13, 1996. Final Report. Office of Scientific and Technical Information (OSTI), January 1997. http://dx.doi.org/10.2172/755539.

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