Modeling Condensate Banking Mitigation by Enhanced Gas Recovery Methods

2021 ◽  
Author(s):  
Adel Mohsin ◽  
Abdul Salam Abd ◽  
Ahmad Abushaikha
Keyword(s):  
Natural Gas ◽  
Finite Difference ◽  
Positive Impact ◽  
Enhanced Recovery ◽  
Gas Production ◽  
Dew Point ◽  
Productivity Index ◽  
Base Case ◽  
Enhanced Gas Recovery ◽  
Gas Recovery

Abstract Condensate banking in natural gas reservoirs can hinder the productivity of production wells dramatically due to the multiphase flow behaviour around the wellbore. This phenomenon takes place when the reservoir pressure drops below the dew point pressure. In this work, we model this occurrence and investigate how the injection of CO2 can enhance the well productivity using novel discretization and linearization schemes such as mimetic finite difference and operator-based linearization from an in-house built compositional reservoir simulator. The injection of CO2 as an enhanced recovery technique is chosen to assess its value as a potential remedy to reduce carbon emissions associated with natural gas production. First, we model a base case with a single producer where we show the deposition of condensate banking around the well and the decline of pressure and production with time. In another case, we inject CO2 into the reservoir as an enhanced gas recovery mechanism. In both cases, we use fully tensor permeability and unstructured tetrahedral grids using mimetic finite difference (MFD) method. The results of the simulation show that the gas and condensate production rates drop after a certain production plateau, specifically the drop in the condensate rate by up to 46%. The introduction of a CO2 injector yields a positive impact on the productivity and pressure decline of the well, delaying the plateau by up to 1.5 years. It also improves the productivity index by above 35% on both the gas and condensate performance, thus reducing production rate loss on both gas and condensate by over 8% and the pressure, while in terms of pressure and drawdown, an improvement of 2.9 to 19.6% is observed per year.

Numerical simulation and optimization of CO2 enhanced gas recovery in homogeneous and vertical heterogeneous reservoir models

2021 ◽  
pp. 1-36
Author(s):  
Shuyang Liu ◽  
Ramesh Agarwal ◽  
Baojiang Sun
Keyword(s):  
Natural Gas ◽  
Injection Rate ◽  
Injection Time ◽  
Upward Migration ◽  
Enhanced Gas Recovery ◽  
Simulation And Optimization ◽  
Heterogeneous Reservoirs ◽  
Gas Recovery ◽  
Heterogeneous Reservoir ◽  
Optimal Injection

Abstract CO2 enhanced gas recovery (CO2-EGR) is a promising, environment-friendly technology with simultaneously sequestering CO2. The goals of this paper are to conduct simulations of CO2-EGR in both homogeneous and heterogeneous reservoirs to evaluate effects of gravity and reservoir heterogeneity, and to determine optimal CO2 injection time and injection rate for achieving better natural gas recovery by employing a genetic algorithm integrated with TOUGH2. The results show that gravity segregation retards upward migration of CO2 and promotes horizontal displacement efficiency, and the layers with low permeability in heterogeneous reservoir hinder the upward migration of CO2. The optimal injection time is determined as the depleted stage, and the corresponding injection rate is optimized. The optimal recovery factors are 62.83 % and 64.75 % in the homogeneous and heterogeneous reservoirs (804.76 m × 804.76 m × 45.72 m), enhancing production by 22.32 × 103 and 23.00 × 103 t of natural gas and storing 75.60 × 103 and 72.40 × 103 t CO2 with storage efficiencies of 70.55 % and 67.56 %, respectively. The cost/benefit analysis show that economic income of about 8.67 and 8.95 million USD can be obtained by CO2-EGR with optimized injection parameters respectively. This work could assist in determining optimal injection strategy and economic benefits for industrial scale gas reservoirs.

Case Study of Condensate Dropout Effect in Unconventional Gas/Condensate Reservoirs with Hydraulically Fractured Wells

2022 ◽  
Author(s):  
Ali H. Alsultan ◽  
Josef R. Shaoul ◽  
Jason Park ◽  
Pacelli L. J. Zitha
Keyword(s):  
Gas Production ◽  
Gas Condensate ◽  
Dew Point ◽  
Productivity Index ◽  
Large Reservoir ◽  
Unconventional Gas ◽  
Gas Condensate Reservoirs ◽  
Liquid Saturation ◽  
Reservoir Volume ◽  
Fracture Performance

Abstract Condensate banking is a major issue in the production operations of gas condensate reservoirs. Increase in liquid saturation in the near-wellbore zone due to pressure decline below dew point, decreases well deliverability and the produced condensate-gas ratio (CGR). This paper investigates the effects of condensate banking on the deliverability of hydraulically fractured wells producing from ultralow permeability (0.001 to 0.1 mD) gas condensate reservoirs. Cases where condensate dropout occurs over a large volume of the reservoir, not only near the fracture face, were examined by a detailed numerical reservoir simulation. A commercial compositional simulator with local grid refinement (LGR) around the fracture was used to quantify condensate dropout as a result of reservoir pressure decline and its impact on well productivity index (PI). The effects of gas production rate and reservoir permeability were investigated. Numerical simulation results showed a significant change in fluid compositions and relative permeability to gas over a large reservoir volume due to pressure decline during reservoir depletion. Results further illustrated the complications in understanding the PI evolution of hydraulically fractured wells in "unconventional" gas condensate reservoirs and illustrate how to correctly evaluate fracture performance in such a situation. The findings of our study and novel approach help to more accurately predict post-fracture performance. They provide a better understanding of the hydrocarbon phase change not only near the wellbore and fracture, but also deep in the reservoir, which is critical in unconventional gas condensate reservoirs. The optimization of both fracture spacing in horizontal wells and well spacing for vertical well developments can be achieved by improving the ability of production engineers to generate more realistic predictions of gas and condensate production over time.

scholarly journals Application of Supergravity Technology in a TEG Dehydration Process for Offshore Platforms

Processes ◽  
2019 ◽  
Vol 7 (1) ◽  
pp. 43 ◽  
Author(s):  
Hongfang Lu ◽  
Guoguang Ma ◽  
Mohammadamin Azimi ◽  
Lingdi Fu
Keyword(s):  
Natural Gas ◽  
Flow Rate ◽  
Packed Bed ◽  
Gas Production ◽  
Dew Point ◽  
Transfer Model ◽  
Offshore Platforms ◽  
Dehydration Process ◽  
Tower Equipment ◽  
Rotating Packed Bed

In the dehydration process of offshore natural gas production, due to the site limitation of the platform, if the conventional triethylene glycol (TEG) dehydration process is employed, the size of the absorption tower is usually small. However, in the case of fluctuations in raw material gas and large gas production, it is easy to cause a large loss of TEG and a flooding event, resulting in the water dew point of natural gas not meeting the requirements. Therefore, combined with the dehydration process of TEG and supergravity technology, a new dehydration process of natural gas suitable for offshore platforms is proposed in this paper. The principle and process of the TEG dehydration process based on supergravity technology are discussed by establishing a mass transfer model. The laboratory experiment of the new process is carried out, and the effects of TEG flow rate, super-gravity packed bed rotation speed, and gas flow rate on the air dew point are obtained. By studying the dewatering balance of the rotating packed bed in the improved process, it is proved that the dewatering performance of the high gravity machine (Higee) is much better than that of the ordinary tower dewatering equipment. Through field experiments, the dewatering effect of continuous operation and sudden changes in working conditions is obtained, indicating that the Higee can completely replace the traditional tower equipment for natural gas dehydration.

Enhanced gas recovery, CO2 storage and implications from the CO2CRC Otway Project

2011 ◽  
Vol 51 (2) ◽  
pp. 684
Author(s):  
Peter Cook ◽  
Yildiray Cinar ◽  
Guy Allinson ◽  
Charles Jenkins ◽  
Sandeep Sharma ◽  
...  
Keyword(s):  
Pore Space ◽  
Co2 Storage ◽  
Co2 Concentration ◽  
Gas Production ◽  
Anthropogenic Sources ◽  
Future Price ◽  
Gas Field ◽  
Enhanced Gas Recovery ◽  
Gas Recovery ◽  
Gas Fields

Successful completion of the first stage of the CO2CRC Otway Project demonstrated safe and effective CO2 storage in the Naylor depleted gas field and confirmed our ability to model and monitor subsurface behaviour of CO2. It also provided information of potential relevance to CO2 enhanced gas recovery (EGR) and to opportunities for CO2 storage in depleted gas fields. Given the high CO2 concentration of many gas fields in the region, it is important to consider opportunities for integrating gas production, CO2 storage in depleted gas fields, and CO2-EGR optimisation within a production schedule. The use of CO2-EGR may provide benefits through the recovery of additional gas resources and a financial offset to the cost of geological storage of CO2 from gas processing or other anthropogenic sources, given a future price on carbon. Globally, proven conventional gas reserves are 185 trillion m3 (BP Statistical Review, 2009). Using these figures and Otway results, a replacement efficiency of 60 % (% of pore space available for CO2 storage following gas production) indicates a global potential storage capacity—in already depleted plus reserves—of approximately 750 Gigatonnes of CO2. While much of this may not be accessible for technical or economic reasons, it is equivalent to more than 60 years of total global stationary emissions. This suggests that not only gas—as a lower carbon fuel—but also depleted gas fields, have a major role to play in decreasing CO2 emissions worldwide.

Research Progress of CO2 Sequestration with Enhanced Gas Recovery

2013 ◽  
Vol 807-809 ◽  
pp. 1075-1079
Author(s):  
Yi Zhang ◽  
Shu Yang Liu ◽  
Yong Chen Song ◽  
Wei Wei Jian ◽  
Duo Li ◽  
...  
Keyword(s):  
Experimental Data ◽  
Natural Gas ◽  
Large Scale ◽  
Economic Feasibility ◽  
Research Progress ◽  
Pilot Projects ◽  
Gas Field ◽  
Enhanced Gas Recovery ◽  
Gas Recovery ◽  
Feasibility Research

CO2Sequestration with Enhanced Gas Recovery (CSEGR) is one of the efficient and attractive scenarios to reduce CO2emission and accelerate gas field to produce more natural gas simultaneously. We review the correlational experiments, simulations and economic feasibility research about technical and economic problems of CSEGR. And the potential of natural gas increase production and CO2emission reduction in China by CSEGR is calculated. The pilot projects and simulation results show that CSEGR is technically feasible when suitable injection strategies and field management are implemented. However, economic feasibility is available only via policies of carbon credit, allowance and trade. Accurate experimental data would ensure the authenticity of key simulation parameters and reliability of simulations, but the existed experimental data is scarce. More experimental researches should be conducted to obtain a great quantity of accurate data which can make the simulation more close to the actual situation. Accordingly, the pilot projects and large-scale applications of CSEGR could be implemented successfully.

Well Completion for Effective Deliquification of Natural Gas Wells

2011 ◽  
Vol 134 (1) ◽  
Author(s):  
John Yilin Wang
Keyword(s):  
Natural Gas ◽  
Operating Cost ◽  
Gas Production ◽  
Gas Wells ◽  
Liquid Loading ◽  
Gas Recovery ◽  
Well Completion ◽  
Reservoir Permeability ◽  
Gas Fields ◽  
Gas Lift

Liquid loading has been a problem in natural gas wells for several decades. With gas fields becoming mature and gas production rates dropping below the critical rate, deliquification becomes more and more critical for continuous productivity and profitability of gas wells. Current methods for solving liquid loading in the wellbore include plunger lift, velocity string, surfactant, foam, well cycling, pumps, compression, swabbing, and gas lift. All these methods are to optimize the lifting of liquid up to surface, which increases the operating cost, onshore, and offshore. However, the near-wellbore liquid loading is critical but not well understood. Through numerical reservoir simulation studies, effect of liquid loading on gas productivity and recovery has been quantified in two aspects: backup pressure and near-wellbore liquid blocking by considering variable reservoir permeability, reservoir pressure, formation thickness, liquid production rate, and geology. Based on the new knowledge, we have developed well completion methods for effective deliquifications. These lead to better field operations and increased ultimate gas recovery.

Dual-membrane natural gas pretreatment process as CO 2 source for enhanced gas recovery with synergy hydrocarbon recovery

2016 ◽  
Vol 34 ◽  
pp. 563-574 ◽  
Author(s):  
Bo Chen ◽  
Xiaobin Jiang ◽  
Wu Xiao ◽  
Yanan Dong ◽  
Issam El Hamouti ◽  
...  
Keyword(s):  
Natural Gas ◽  
Enhanced Gas Recovery ◽  
Hydrocarbon Recovery ◽  
Gas Recovery

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.

Study of Use of Supercritical CO2 to Enhance Gas Recovery and its Interaction With Carbonate Reservoirs

2013 ◽  
Author(s):  
Hicham El Hajj ◽  
Uchenna Odi ◽  
Anuj Gupta
Keyword(s):  
Carbonate Reservoir ◽  
Dew Point ◽  
Productivity Index ◽  
Gas Recovery ◽  
Carbonate Formation ◽  
Wet Gas ◽  
Point Pressure ◽  
Condensate Blockage ◽  
Simulation Results ◽  
Dew Point Pressure

It is well known that with continued production from wet gas reservoirs, the reservoir pressure eventually falls below the dew point pressure leading to condensation and loss of gas productivity in the reservoir. The concept of simultaneously injecting CO2 in a gas reservoir for long term storage while at the same time accelerating production of the natural gas is intriguing and promising. CO2 may also interact with carbonate matrix by changing porosity and permeability of the host rock; this is true for reservoirs that are found in the Gulf Region. To maintain field gas production targets, operators routinely set the bottom hole pressure below the dew point pressure which results in condensate blockage. Injecting CO2 can delay the onset of condensate blockage by reducing the dew point pressure of the condensate blockage zone. The approach illustrated, utilizes CO2 to delay the onset of condensate blockage. Factors such as improved effusion were analyzed to justify the use of CO2 for wellbore condensate removal and enhanced gas recovery (EGR). Experimental verification of a new method of determining dew point pressures for wet gas fluids is presented in this work and compared to simulation results. Core floods experiments with carbon dioxide were conducted in a core sample analogue to carbonate at reservoir conditions in order to study the interaction between CO2 and carbonate reservoir. CO2 sequestration in carbonate formation was evaluated by XRF and AFM. Experimental and simulation results show increases in productivity index after CO2 injection. Increases in productivity index were caused by CO2 evaporating the condensate blockage. Condensate vaporization was caused by CO2 reducing the dew point pressure of the condensate. Carbonate aging in presence of CO2 shows two mechanism of CO2 trapping which are dissolution and mineralization.

Sign in / Sign up

Export Citation Format

Share Document