scholarly journals Studying the influence of the carbon dioxide injection period duration on the gas recovery factor during the gas condensate fields development under water drive

2021 ◽  
Vol 15 (2) ◽  
pp. 95-101
Author(s):  
Serhii Matkivskyi ◽  
Oleksandr Kondrat
Keyword(s):  
Carbon Dioxide ◽  
Gas Condensate ◽  
Recovery Factor ◽  
Water Inflow ◽  
Formation Water ◽  
Carbon Dioxide Injection ◽  
Water Contact ◽  
Hydrocarbon Recovery ◽  
Injection Period ◽  
Gas Recovery

Purpose. Studying the process of carbon dioxide injection at the boundary of the initial gas-water contact in order to slow down the formation water inflow into producing reservoirs and increase the final hydrocarbon recovery factors. Methods. To assess the influence on gas recovery factor of the duration of carbon dioxide injection period at the initial gas-water contact, a reservoir development is studied using the main Eclipse and Petrel hydrodynamic modeling tools of the Schlumberger company on the example of a hypothetical three-dimensional model of a gas-condensate reservoir. Findings. The dependence of the main technological indicators of reservoir development on the duration of the carbon dioxide injection period at the initial gas-water contact has been determined. It has been revealed that an increase in the duration of the non-hydrocarbon gas injection period leads to a decrease in the formation water cumulative production. It has been found that when injecting carbon dioxide, an artificial barrier is created due to which the formation water inflow into the gas-saturated intervals of the productive horizon is partially blocked. The final gas recovery factor when injecting carbon dioxide is 61.98%, and when developing the reservoir for depletion – 48.04%. The results of the research performed indicate the technological efficiency of carbon dioxide injection at the boundary of the initial gas-water contact in order to slow down the formation water inflow into producing reservoirs and increase the final hydrocarbon recovery factors for the conditions of a particular field. Originality. The optimal value of duration of the carbon dioxide injection period at the initial gas-water contact has been determined, which is 16.32 months based on the statistical processing of calculated data for the conditions of a particular field. Practical implications. The use of the results makes it possible to improve the existing technologies for the gas condensate fields development under water drive and to increase the final hydrocarbon recovery factor.

scholarly journals Effects of the rate of carbon dioxide injection at the initial gas-water contact on the recovery factor

2020 ◽  
pp. 23-30
Author(s):  
О. R. Kondrat ◽  
S. V. Matkivskyi ◽  
О. V. Burachok ◽  
L. І. Haidarova
Keyword(s):  
Carbon Dioxide ◽  
Natural Gas ◽  
Injection Rate ◽  
Gas Condensate ◽  
Recovery Factor ◽  
Formation Water ◽  
Carbon Dioxide Injection ◽  
Water Contact ◽  
Gas Recovery ◽  
Production Wells

The process of carbon dioxide injection into the initial gas-water contact with different rates of its injection, using a 3D model of a gas condensate reservoir, has been investigated. Calculations were carried out for one well injection rate of non-hydrocarbon gas: 40, 50, 60, 70, 80, 90 th.m3/day. According to the calculated results, it has been found that with an increased rate of the carbon dioxide injection into a productive reservoir, the operation duration of production wells decreases until the moment of the carbon dioxide breakthrough. Based on the techno-logical indicators’ analysis of the gas condensate reservoir’s development, it has been found that the introduction of the carbon dioxide injecting technology leads to a reduction in the production of formation water. Due to the injec-tion of non-hydrocarbon gases, a hydrodynamic barrier is created on the initial gas-water contact boundary, which decreases the water influx. Also, the introduction of carbon dioxide injection technology will additionally create an artificial barrier between water and natural gas, which blocks the selective water encroaching and thereby ensure stable waterless operation of production wells. Based on the conducted calculations, the main dependencies have been derived and the corresponding patterns between them have been established. According to the results of the statistical processing of the calculated data, the optimal carbon dioxide injection rate has been determined. At the time of the carbon dioxide breakthrough into the producing well, its optimal well injection rate is 58.17 th.m3/day. The ultimate gas recovery factor for the optimal carbon dioxide injection rate is 63.29 %. Under the same condi-tions during depletion, the ultimate natural gas recovery factor is 53.98%. The results of the carried out studies indicate the technological efficiency of carbon dioxide injection into the initial gas-water contact in order to slow down the formation water encroaching into productive reservoir.

scholarly journals Effects of the rate of natural gas production on the recovery factor during carbon dioxide injection at the initial gas-water contact

2021 ◽  
Vol 1 (3(57)) ◽  
pp. 6-11
Author(s):  
Serhii Matkivskyi
Keyword(s):  
Carbon Dioxide ◽  
Natural Gas ◽  
Gas Production ◽  
Gas Condensate ◽  
Recovery Factor ◽  
Formation Water ◽  
Hydrocarbon Gases ◽  
Water Contact ◽  
Natural Gas Production ◽  
Gas Recovery

The object of research is gas condensate reservoirs, which is being developed under the conditions of the manifestation of the water drive of development and the negative effect of formation water on the process of natural gas production. The results of the performed theoretical and experimental studies show that a promising direction for increasing hydrocarbon recovery from fields at the final stage of development is the displacement of natural gas to producing wells by injection non-hydrocarbon gases into productive reservoirs. The final gas recovery factor according to the results of laboratory studies in the case of injection of non-hydrocarbon gases into productive reservoirs depends on the type of displacing agent and the level heterogeneity of reservoir. With the purpose update the existing technologies for the development of fields in conditions of the showing of water drive, the technology of injection carbon dioxide into productive reservoirs at the boundary of the gas-water contact was studied using a digital three-dimensional model of a gas condensate deposit. The study was carried out for various values of the rate of natural gas production. The production well rate for calculations is taken at the level of 30, 40, 50, 60, 70, 80 thousand m3/day. Based on the data obtained, it has been established that an increase in the rate of natural gas production has a positive effect on the development of a productive reservoir and leads to an increase in the gas recovery factor. Based on the results of statistical processing of the calculated data, the optimal value of the rate of natural gas production was determined when carbon dioxide is injected into the productive reservoir at the boundary of the gas-water contact is 55.93 thousand m3/day. The final gas recovery factor for the optimal natural gas production rate is 64.99 %. The results of the studies carried out indicate the technological efficiency of injecting carbon dioxide into productive reservoirs at the boundary of the gas-water contact in order to slow down the movement of formation water into productive reservoirs and increase the final gas recovery factor.

scholarly journals Investigation of the influence of the carbon dioxide (CO2) injection rate on the activity of the water pressure system during gas condensate fields development

2021 ◽  
Vol 230 ◽  
pp. 01011
Author(s):  
Serhii Matkivskyi ◽  
Oleksandr Kondrat ◽  
Oleksandr Burachok
Keyword(s):  
Carbon Dioxide ◽  
Water Pressure ◽  
Gas Production ◽  
Gas Condensate ◽  
Co2 Injection ◽  
Final Decision ◽  
Water Production ◽  
Carbon Dioxide Injection ◽  
Pressure System ◽  
Water Contact

The development of gas condensate fields under the conditions of elastic water drive is characterized by uneven movement of the gas-water. Factors of hydrocarbon recovery from producing reservoirs which are characterized by the active water pressure drive on the average make up 50-60%. To increase the efficiency of fields development, which are characterized by an elastic water drive, a study of the effect of different volumes of carbon dioxide injection at the gas-water contact on the activity of the water pressure system and the process of flooding producing wells was carried out. Using a three-dimensional model, the injection of carbon dioxide into wells located at the boundary of gas-water contact with flow rates from 20 to 500 thousand m3/day was investigated. Analyzing the simulation data, it was found that increasing the volume of carbon dioxide injection provides an increase in accumulated gas production and a significant reduction in water production. The main effect of the introduction of this technology is achieved by increasing the rate of carbon dioxide injection to 300 thousand m3/day. The set injection rates allowed us to increase gas production by 67% and reduce water production by 83.9% compared to the corresponding indicators without injection of carbon dioxide. Taking into account above- mentioned, the final decision on the introduction of carbon dioxide injection technology and optimal technological parameters of producing and injection wells operation should be made on the basis of a comprehensive technical and economic analysis using modern methods of the hydrodynamic modeling of reservoir systems.

scholarly journals The influence of nitrogen injection duration at the initial gas-water contact on the gas recovery factor

2021 ◽  
Vol 1 (6 (109)) ◽  
pp. 77-84
Author(s):  
Serhii Matkivskyi ◽  
Oleksandr Kondrat
Keyword(s):  
Recovery Factor ◽  
Water Production ◽  
Reservoir Water ◽  
Water Contact ◽  
Gas Recovery ◽  
Nitrogen Injection ◽  
Injection Duration ◽  
Study Results ◽  
Production Wells ◽  
Hydrocarbon Gas

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 %

Fractional Flow Analysis of Displacement in a CO2 Enhanced Gas Recovery Process for Carbonate Reservoirs

2012 ◽  
Author(s):  
Uchenna Odi ◽  
Anuj Gupta
Keyword(s):  
Carbon Dioxide ◽  
Flow Analysis ◽  
Material Balance ◽  
Relative Effect ◽  
Carbonate Reservoir ◽  
Gas Condensate ◽  
Fractional Flow ◽  
Enhanced Gas Recovery ◽  
Gas Recovery ◽  
Oil Gas

This paper presents fractional flow analysis of displacement of gas/condensate in a wet/condensate gas reservoir by CO2 that includes interactions between CO2 and condensate. Phase behavior affects the performance of carbon dioxide enhanced oil/ gas recovery processes in a significant manner. It also controls the effectiveness of carbon dioxide sequestration processes. In the past, there has been a focus on understanding interactions of CO2 with matrix and other fluids in oil reservoirs by various researchers. However, there is now an increasing interest in understanding carbon dioxide interactions in gas condensate reservoirs so that CO2 can be used to increase recovery. For a carbonate reservoir containing gas-condensates, this new focus requires a fundamental understanding of the interactions of carbon dioxide with condensate and gas phases. This paper describes the relative effect that these mechanisms have by conducting a fractional flow analysis for Enhanced Gas Recovery. These mechanisms include miscibility and partitioning of CO2 in various phases. Understanding these mechanisms is essential to modeling Enhanced Oil/Gas Recovery using CO2. The analysis honors the material balance and accounts for miscibility between carbon dioxide and condensate. The results of the fractional flow analysis are important for validation of computer simulation of the comparable processes. This work is expected to serve as a foundation work in understanding the mechanisms involved in CO2 assisted enhanced oil and gas recovery.

Dry Gas Reinjection in a Strong Waterdrive Gas-Condensate Field Increases Condensate Recovery—Case Study: The Sleipner Øst Ty Field, South Viking Graben, Norwegian North Sea

2009 ◽  
Vol 12 (02) ◽  
pp. 281-296 ◽  
Author(s):  
Kjersti M. Eikeland ◽  
Helga Hansen
Keyword(s):  
North Sea ◽  
Northern Region ◽  
Gas Condensate ◽  
Drop Out ◽  
Recovery Factor ◽  
High Porosity ◽  
Reservoir Pressure ◽  
Drainage Pattern ◽  
Injection Period ◽  
Pressure Depletion

Summary The Sleipner Øst Ty field is a strong waterdrive gas/condensate field, with in-place volumes of 59×109Sm3 dry gas and 52×106Sm3 unstabilized condensate. The reservoir consists of deepwater turbidite sandstones and associated mudstones, which act as baffles to flow. The reservoir qualities are very good, with high porosity and with permeability in the range of 100 to 1,000 md. The first production in the area began at the Sleipner Øst Ty field in 1993. The initial reservoir pressure of 244 bar (2.44×104 kPa) is only a few bar above the dewpoint pressure. Massive dry-gas reinjection started in 1996, and the reservoir pressure increased during the next two years, which caused an increase in the condensate-to-gas ratio. During the injection period, which lasted until 2005, 29×109Sm3 of dry gas was injected. The main focus during these years was to obtain good vertical and areal sweep of the dry gas in order to vaporize the dropped-out condensate. Chemical gas tracers were injected and analyzed for in the production wells to monitor the movement of the dry gas through the reservoir. This knowledge was used to identify unswept areas, and to change the drainage pattern by conducting well interventions and drilling infill wells. The injection was stopped primarily because of high probability of trapping gas. Compositional reservoir simulation showed that from 10 to 20% of the injected dry-gas volume could be trapped in the northern region, which has no producers. The risk of not being able to back-produce the injected dry gas was considered high, since the saddle area separating the producers in the south from the injectors in the north was invaded by the aquifer. The gas cycling program has increased the condensate recovery factor substantially; from the originally planned 50% by pressure depletion, to the current estimated ultimate recovery of 81%. As of July 2007, the condensate recovery factor is 76%. Introduction The Sleipner Øst Ty field is located in production license PL046 in the Sleipner area in the southern part of the Viking Graben, Norwegian North Sea, Fig. 1. It was discovered in 1981 by exploration Well 15/9-9, and appraised and developed during the next 12 years. A total of four exploration wells, 13 producers and five injectors have been drilled. On the basis of the well information, the in-place volumes have been calculated to 59×109Sm3 dry gas and 52×106Sm3 unstabilized condensate. The production started in 1993 from the Sleipner A platform, a fully integrated gravity base platform, and a connected subsea template with two producers. Water depth in the area is 82 m. The field is operated by StatoilHydro ASA with their license partners ExxonMobil Norway AS and Total Norge AS. The field was originally planned to be produced by pressure depletion, but a revised drainage strategy recommended dry-gas reinjection to increase the condensate recovery. Hence, as soon as plateau production was achieved and gas sales commitments were fulfilled, a recycling program of the surplus dry gas was started. However, for the first two years, the injected volumes were small. It was not until the large neighboring gas/condensate field Sleipner Vest came on stream in 1996 that massive gas reinjection was possible. Since the initial reservoir pressure was only a few bar above the dewpoint pressure, condensate started to drop out in the reservoir immediately after production commenced 1993. The dry-gas reinjection has been important both to revaporize this dropped-out condensate and to keep the pressure high in order to prevent further condensate drop out in the reservoir. This paper will present how the reinjection of dry gas into the Ty reservoir has increased the condensate recovery substantially compared to a pure depletion drainage strategy. The strong aquifer has given important pressure support during the production history. When the injection period ended, blowdown of the field was accelerated to maximize the recovery. The time-line diagram in Fig. 2 illustrates the major events in the field's lifetime.

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