Process Modeling of CO2Injection into Natural Gas Reservoirs for Carbon Sequestration and Enhanced Gas Recovery

2001 ◽  
Vol 15 (2) ◽  
pp. 293-298 ◽  
Author(s):  
C. M. Oldenburg ◽  
K. Pruess ◽  
S. M. Benson
Keyword(s):  
Carbon Sequestration ◽  
Natural Gas ◽  
Process Modeling ◽  
Gas Reservoirs ◽  
Enhanced Gas Recovery ◽  
Gas Recovery ◽  
Natural Gas Reservoirs

scholarly journals Approbation of the technology for displacing residual gas with nitrogen for the conditions of a depleted gas reservoir in the VS-9 horizon of the Lyubeshivske gas field

2020 ◽  
pp. 16-23
Author(s):  
R. M. Kondrat ◽  
L. I. Khaidarova
Keyword(s):  
Natural Gas ◽  
Gas Reservoirs ◽  
Gas Field ◽  
Recovery Coefficient ◽  
Gas Recovery ◽  
Production Wells ◽  
Depleted Gas Reservoirs ◽  
Reser Voirs ◽  
Residual Gas ◽  
Natural Gas Reservoirs

Most natural gas reservoirs of Ukraine are depleted to some extent; still they contain significant tail gas reserves. A promising direction for increasing gas recovery from depleted gas reservoirs is the displacement of tail gas from the porous medium with nitrogen which is easily accessible and does not cause corrosion of the down-hole equipment. This article characterizes the technologies for increasing gas recovery from depleted gas reser-voirs by injecting nitrogen into them. The technology of replacing tail gas with nitrogen is tested on the example of the depleted reservoir of ND-9 horizon of Lyubeshivskyy gas field, the productive deposits of which are composed mainly of sandstones with interlayers of limestone and clay. The authors consider fifteen options of injecting ni-trogen into the reservoir, including options of treating the bottom-hole of low-production wells at the beginning of the process of further reservoir development and at the beginning of the injection of nitrogen into the reservoir. In all cases, the reservoir is first redeveloped in the depletion mode until the reservoir pressure decreases to 0,1 from the initial value. After that, nitrogen is injected into one of the producing wells which is transferred to the injection well. The injection of nitrogen into the reservoir continues until the nitrogen content in the last produc-ing well is less than 5 % vol. All options are characterized by high values of the gas recovery coefficient and close values of the dura-tion of the reservoir further development. The positions of the front of the displacement of natural gas by nitrogen at various time points are given. According to the research results, the gas recovery coefficient for tail gas for var-ious options varies from 14,12 to 34,58 %. With the introduction of the technology of injecting nitrogen into the reservoir, the overall gas recovery coefficient increases from 72,25 % (at present development system) to 80,28 % when the residual gas is displaced by nitrogen.

scholarly journals Case study on diagnosis and identify the degree of bottom hole liquid accumulation in double-branch horizontal wells in PCOC

2021 ◽  
Vol 248 ◽  
pp. 01071
Author(s):  
Tingwei Yao ◽  
Yang Zhang ◽  
Minhao Guo ◽  
Zhilin Tuo ◽  
Haiyang Wang ◽  
...  
Keyword(s):  
Natural Gas ◽  
Large Scale ◽  
Gas Flow ◽  
Continuous Production ◽  
Production Performance ◽  
Gas Wells ◽  
Gas Reservoirs ◽  
Gas Recovery ◽  
Bottom Hole ◽  
Natural Gas Reservoirs

In the process of continuous production of natural gas wells, formation pressure and gas flow rate decrease continuously. The ability to carry liquid decreases continuously, thus gradually forming bottom hole liquid. Bottom hole liquid accumulation is an important reason for the decrease of production or shutdown of natural gas wells. How to diagnose whether there is liquid accumulation in natural gas wells and identify the degree of liquid accumulation, to adopt drainage gas recovery operation in time, is the research focus of efficient development of natural gas reservoirs. In this paper, a method for diagnosing bottom hole liquid accumulation combining production performance curve and modified Fernando inclined well critical liquid-carrying model is designed for a large scale double-branch horizontal well used in unconventional reservoirs. The method is applied to the Well X2 of He 8 Member in PCOC. The application results showed that there was no liquid accumulation in the horizontal and vertical sections of the Well X2. The liquid in the wellbore was generated at the bottom of the inclined section and the liquid accumulation is upward along the wellbore from the bottom of the inclined section, with the height of 3 m.

The Feasibility Appraisal for CO2 Enhanced Gas Recovery of Tight Gas Reservoir: Case Analysis and Economic Evaluation

2021 ◽  
Author(s):  
Ying Jia ◽  
Yunqing Shi ◽  
Jin Yan
Keyword(s):  
Natural Gas ◽  
Greenhouse Gas Emission ◽  
Co2 Storage ◽  
Tight Gas ◽  
Gas Reservoirs ◽  
Gas Reservoir ◽  
Enhanced Gas Recovery ◽  
Tight Gas Reservoirs ◽  
Gas Recovery ◽  
Tight Gas Reservoir

Abstract Tight gas reservoirs are widely distributed in China, which occupies one-third of the total resources of natural gas. The typical development method is under primary depletion. However, the recovery of tight gas is only around 20%. It is necessary to explore a new technique to improve tight gas recovery. Injecting CO2 into tight gas reservoirs is a novel trial to enhance gas recovery. The objective of this work is to verify and evaluate the effect supercritical CO2 on enhancing gas recovery and analyze the feasibility of CO2 enhance gas recovery of tight gas reservoir. Taken DND tight sandstone gas reservoir in North China as an example, 34 wells of DK13 wellblock were chosen as CO2 Enhanced gas recovery pilot area with 10-year production history. Six injection scenarios were studied. Numerical simulation indicated that the recovery of the gas reservoir of DK13 well area was improved by 8-9.5 percent when CO2 content of producers reaches 10 percent. The annual CO2 Storage would be 62 million cubic meters (110 thousand tons) and the total CO2 storage would be around 800million cubic meters (1.5 million tons). After the environmental parameter evaluation of injectors and producers, the anticorrosion schemes were put forward and the feasibility evaluation and schemes of facilities were presented. The analysis results indicated that DK13 wellblock was suitable for CO2 enhanced gas recovery no matter geologic condition, injection & production technology and facilities. However, under the current economic conditions, DK13 wellblock was not suitable for CO2to enhance gas recovery. However, if gas price rise or low carbon strategy implement, the pilot test could be carried out. In brief, CO2 could be an attractive option to successfully displace natural gas and decrease CO2 emissions, which is a promising technology for reducing greenhouse gas emission and increasing the ultimate gas recovery of tight gas reservoirs. This economic analysis, along with reservoir simulation and laboratory studies that suggest the technical feasibility of CSEGR, demonstrates that CSEGR can be feasible and that a field pilot study of the process should be undertaken to test the concept further.

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.

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