Reservoir Simulation of CO2 Sequestration in Shale Reservoir

2021 ◽  
Author(s):  
Qin He ◽  
Teresa Reid ◽  
Guofang Zheng
Keyword(s):  
Reservoir Simulation ◽  
Coalbed Methane ◽  
Co2 Sequestration ◽  
Carbon Capture ◽  
Gas Production ◽  
Small Scale ◽  
Gas Recovery ◽  
Service Companies ◽  
Shale Reservoir ◽  
Shale Reservoirs

Abstract Increased production in natural gas from shale reservoirs has sparked concern that greenhouse gas emissions have also been on the rise. As a result, large- and small-scale operators and service companies are enthusiastically supporting a push toward "net carbon zero emissions". Carbon capture utilization and storage (CCUS) is playing an impactful role in companies’ goals to reach net zero. CO2 sequestration is the process of capturing and storing CO2 emissions from industrial and energy-related sources. Most CO2 sequestration are recommended to locate in saline aquifer, coalbed zone and depleted reservoirs, while CO2 sequestration in shale reservoir could become another good option to minimize the environmental footprint and enhance the gas production. Similar as CO2 sequestration into coalbed methane reservoir, the fluid flow mechanism in shale also includes desorption, diffusion and Darcy's law. In this paper, the effects of CO2 sequestration on shale reservoirs will be discussed from a technical and economical viewpoint. A reservoir simulation was used to evaluate the quantity of CO2 that can be stored in shale, the effects of CO2 mitigation when injected into shale, and any significant opportunities for CO2 enhanced shale gas recovery. Lastly, an economic analysis was performed to evaluate the economic efficiency of such projects in shales.

scholarly journals Molecular Investigation on the Displacement Characteristics of CH4 by CO2, N2 and Their Mixture in a Composite Shale Model

Energies ◽  
2020 ◽  
Vol 14 (1) ◽  
pp. 2
Author(s):  
Liang Gong ◽  
Yuan Zhang ◽  
Na Li ◽  
Ze-Kai Gu ◽  
Bin Ding ◽  
...  
Keyword(s):  
Energy Consumption ◽  
Shale Gas ◽  
Injection Pressure ◽  
Gas Production ◽  
Formation Temperature ◽  
Displacement Efficiency ◽  
Gas Recovery ◽  
Displacement Capacity ◽  
Molecular Investigation ◽  
Shale Reservoirs

The rapid growth in energy consumption and environmental pollution have greatly stimulated the exploration and utilization of shale gas. The injection of gases such as CO2, N2, and their mixture is currently regarded as one of the most effective ways to enhance gas recovery from shale reservoirs. In this study, molecular simulations were conducted on a kaolinite–kerogen IID composite shale matrix to explore the displacement characteristics of CH4 using different injection gases, including CO2, N2, and their mixture. The results show that when the injection pressure was lower than 10 MPa, increasing the injection pressure improved the displacement capacity of CH4 by CO2. Correspondingly, an increase of formation temperature also increased the displacement efficiency of CH4, but an increase of pore size slightly increased this displacement efficiency. Moreover, it was found that when the proportion of CO2 and N2 was 1:1, the displacement efficiency of CH4 was the highest, which proved that the simultaneous injection of CO2 and N2 had a synergistic effect on shale gas production. The results of this paper will provide guidance and reference for the displacement exploitation of shale gas by injection gases.

CO2 Injection Performance in the Fruitland Coal Fairway, San Juan Basin: Results of a Field Pilot

SPE Journal ◽  
2011 ◽  
Vol 16 (04) ◽  
pp. 864-879 ◽  
Author(s):  
Anne Y. Oudinot ◽  
George J. Koperna ◽  
Zeno G. Philip ◽  
Ning Liu ◽  
Jason E. Heath ◽  
...  
Keyword(s):  
Coalbed Methane ◽  
The United States ◽  
Gas Production ◽  
Injection Well ◽  
Co2 Injection ◽  
Small Scale ◽  
Steady Increase ◽  
San Juan ◽  
Coal Seams ◽  
Production Wells

Summary The Pump Canyon CO2-enhanced coalbed methane (ECBM)/ sequestration demonstration in New Mexico has the primary objective of demonstrating the feasibility of CO2 sequestration in deep, unmineable coal seams through a small-scale geologic sequestration pilot. This project is not the first of its kind; several small- or large-scale pilots were already conducted previously in the United States [Allison Unit (Reeves et al. 2003) in the San Juan, Appalachian, and Warrior basins] as well as internationally [the Recopol (Reeves and Oudinot 2002) project in Poland, and the Yubari project in Japan, Canada, and Australia]. Additional pilots are currently under way. At the project site, a new CO2-injection well was drilled within an existing pattern of coalbed-methane-production wells. Primarily operated by ConocoPhillips, these wells produce from the Late Cretaceous Fruitland coals. CO2 injection into these coal seams was initiated in late July 2008 and ceased in August 2009. A variety of monitoring, verification, and accounting (MVA) methods were employed to track the movement of the CO2 in order to determine the occurrence of leakage. Within the injection well, MVA methods included continuous measurement of injection volumes, pressures, and temperatures. The offset production wells sampled gas-production rates, pressures, and gas composition through CO2 sensors, tracers in the injected CO2, time-lapse vertical seismic profiling, and surface tiltmeter arrays. A detailed study of the overlying Kirtland shale was also conducted to investigate the integrity of this primary caprock. This information was used to develop a detailed geologic characterization and reservoir model that has been used to further understand the behavior of this reservoir. The CO2-injection pilot has ended with no significant CO2 buildup occurring in the offset production wells. However, a small but steady increase in CO2 and N2 at two of the offset wells may have been an indication of imminent breakthrough. More recent gas samples are, however, showing a decrease in CO2 and N2 content at those wells. This paper describes the project, covering the regulatory process and injection-well construction, the different techniques used to monitor for CO2 leakage, and the results of the modeling work.

scholarly journals Regeneration of unconventional natural gas by methanogens co-existing with sulfate-reducing prokaryotes in deep shale wells in China

2020 ◽  
Vol 10 (1) ◽  
Author(s):  
Yimeng Zhang ◽  
Zhisheng Yu ◽  
Yiming Zhang ◽  
Hongxun Zhang
Keyword(s):  
Natural Gas ◽  
Produced Water ◽  
Gas Production ◽  
Biogenic Methane ◽  
Sulfate Reducing ◽  
Gas Recovery ◽  
Stable Isotopic ◽  
Unconventional Natural Gas ◽  
Acetoclastic Methanogenesis ◽  
Shale Reservoirs

Abstract Biogenic methane in shallow shale reservoirs has been proven to contribute to economic recovery of unconventional natural gas. However, whether the microbes inhabiting the deeper shale reservoirs at an average depth of 4.1 km and even co-occurring with sulfate-reducing prokaryote (SRP) have the potential to produce biomethane is still unclear. Stable isotopic technique with culture-dependent and independent approaches were employed to investigate the microbial and functional diversity related to methanogenic pathways and explore the relationship between SRP and methanogens in the shales in the Sichuan Basin, China. Although stable isotopic ratios of the gas implied a thermogenic origin for methane, the decreased trend of stable carbon and hydrogen isotope value provided clues for increasing microbial activities along with sustained gas production in these wells. These deep shale-gas wells harbored high abundance of methanogens (17.2%) with ability of utilizing various substrates for methanogenesis, which co-existed with SRP (6.7%). All genes required for performing methylotrophic, hydrogenotrophic and acetoclastic methanogenesis were present. Methane production experiments of produced water, with and without additional available substrates for methanogens, further confirmed biomethane production via all three methanogenic pathways. Statistical analysis and incubation tests revealed the partnership between SRP and methanogens under in situ sulfate concentration (~ 9 mg/L). These results suggest that biomethane could be produced with more flexible stimulation strategies for unconventional natural gas recovery even at the higher depths and at the presence of SRP.

DESIGN OF DOMESTIC SCALE BIO-DIGESTER ASSEMBLY, EXPERIMENTATION FOR BIOGAS PRODUCTION AND COMPARISON OF RESULTS WITH CONVENTIONAL DIGESTER

2015 ◽  
Vol 75 (11) ◽  
Author(s):  
Susmita Mishra ◽  
Srinivas Tenneti ◽  
Suman Mishra
Keyword(s):  
Biogas Production ◽  
Gas Production ◽  
Small Scale ◽  
Physical Constraints ◽  
Gas Recovery ◽  
Internal Mixing ◽  
Pros And Cons ◽  
Pressure Swing ◽  
Individual Scale ◽  
Plant Capacity

The work explored various digesters that are currently under implementation, explored their pros and cons and designed a digestion gas collection mechanism suitable for small scale applications. Internal mixing being uneconomical in the domestic and individual scale, it is not being practiced which has to be compensated with large hydraulic retention time to prevent sludge accumulation and scum formation. This in turn reduces the plant capacity for gas production. Our design configuration incorporates automatic and controlled pressure swing mechanisms incorporated by the gas production which acts as the driving force for slurry circulation in the digester and promotes gas recovery as well as improve digestion efficiency. The configuration was run  in 20 l and 50 L scales  and observed for the physical constraints encountered during  operation, recorded for change in digestion parameters with changes in substrate and organic loading rates and also recorded the gas production which was compared with the results in the literature as well as conventionally operated domestic  scale digesters.  

Modeling Fracture-Fluid Cleanup in Tight-Gas Wells

SPE Journal ◽  
2010 ◽  
Vol 15 (03) ◽  
pp. 783-793 ◽  
Author(s):  
John Yilin* Wang ◽  
Stephen A. Holditch ◽  
Duane A. McVay
Keyword(s):  
Reservoir Simulation ◽  
Gas Production ◽  
Base Case ◽  
Tight Gas ◽  
Gas Wells ◽  
Gas Reservoirs ◽  
Data Set ◽  
Gas Recovery ◽  
Modeling Fracture ◽  
Fracture Fluid

Summary On occasion, a hydraulically fractured tight-gas well does not perform up to its potential because of slow or incomplete fracture- fluid cleanup. A number of papers have been written to address individual factors related to fracture-fluid cleanup, but many questions as to which factors mostly affect gas production from such wells remain unanswered. Numerical reservoir simulation is one of the best methods to study the fracture-fluid-cleanup problem. Continuing from our previous publication (Wang et al. 2008) on the effect of gel damage on fracture cleanup, we used reservoir simulation to analyze systematically the factors that affect fracture- fluid cleanup and gas recovery from tight-gas wells. We first developed a comprehensive data set for typical tight gas reservoirs and then ran single-phase-flow cases for each reservoir and fracture scenario to establish the idealized base-case gas recovery. We then systematically evaluated the following factors: multiphase gas and water flow, proppant crushing, polymer filter cake, and, finally, yield stress of concentrated gel in the fracture. The gel in the fracture is concentrated because of fluid leakoff during the fracture treatment. We evaluated these factors additively in the order listed. We found that the most important factor that reduces fracture-fluid cleanup and gas recovery is the gel strength of the fluid that remains in the fracture at the end of the treatment. This paper illustrates the complexity of the fracture-fluid- cleanup problem and points out the need to use reservoir simulation and to include all the pertinent factors to model fracture-fluid cleanup rigorously. The procedures presented can provide a useful, systematic guide to engineers in conducting a numerical simulation study of fracture-fluid cleanup.

Central Appalachian Basin Unconventional (Coal/Organic Shale) Reservoir Small Scale CO2 Injection Test

2018 ◽  
Author(s):  
Michael Karmis ◽  
Nino Ripepi ◽  
Ellen Gilliland ◽  
Andrew Louk ◽  
Xu Tang ◽  
...  
Keyword(s):  
Appalachian Basin ◽  
Small Scale ◽  
Injection Test ◽  
Shale Reservoir ◽  
Organic Shale

scholarly journals A Comprehensive Coal Reservoir Classification Method Base on Permeability Dynamic Change and Its Application

Energies ◽  
2020 ◽  
Vol 13 (3) ◽  
pp. 644 ◽  
Author(s):  
Xinlu Yan ◽  
Songhang Zhang ◽  
Shuheng Tang ◽  
Zhongcheng Li ◽  
Yongxiang Yi ◽  
...  
Keyword(s):  
Coalbed Methane ◽  
Dynamic Change ◽  
Initial Permeability ◽  
Gas Production ◽  
Gas Desorption ◽  
Reservoir Permeability ◽  
Geological Conditions ◽  
Production Stages ◽  
Productivity Potential ◽  
Coal Reservoir

Due to the unique adsorption and desorption characteristics of coal, coal reservoir permeability changes dynamically during coalbed methane (CBM) development. Coal reservoirs can be classified using a permeability dynamic characterization in different production stages. In the single-phase water flow stage, four demarcating pressures are defined based on the damage from the effective stress on reservoir permeability. Coal reservoirs are classified into vulnerable, alleviative, and invulnerable reservoirs. In the gas desorption stage, two demarcating pressures are used to quantitatively characterize the recovery properties of permeability based on the recovery effect of the matrix shrinkage on permeability, namely the rebound pressure (the pressure corresponding to the lowest permeability) and recovery pressure (the pressure when permeability returns to initial permeability). Coal reservoirs are further classified into recoverable and unrecoverable reservoirs. The physical properties and influencing factors of these demarcating pressures are analyzed. Twenty-six wells from the Shizhuangnan Block in the southern Qinshui Basin of China were examined as a case study, showing that there is a significant correspondence between coal reservoir types and CBM well gas production. This study is helpful for identifying geological conditions of coal reservoirs as well as the productivity potential of CBM wells.

scholarly journals Quantify Coal Macrolithotypes of a Whole Coal Seam: A Method Combing Multiple Geophysical Logging and Principal Component Analysis

Energies ◽  
2021 ◽  
Vol 14 (1) ◽  
pp. 213
Author(s):  
Chao Cui ◽  
Suoliang Chang ◽  
Yanbin Yao ◽  
Lutong Cao
Keyword(s):  
Principal Component Analysis ◽  
Coal Seam ◽  
Coalbed Methane ◽  
Principal Component ◽  
Component Analysis ◽  
Gas Production ◽  
Index Model ◽  
Geophysical Logging ◽  
The Relationship ◽  
Observation Results

Coal macrolithotypes control the reservoir heterogeneity, which plays a significant role in the exploration and development of coalbed methane. Traditional methods for coal macrolithotype evaluation often rely on core observation, but these techniques are non-economical and insufficient. The geophysical logging data are easily available for coalbed methane exploration; thus, it is necessary to find a relationship between core observation results and wireline logging data, and then to provide a new method to quantify coal macrolithotypes of a whole coal seam. In this study, we propose a L-Index model by combing the multiple geophysical logging data with principal component analysis, and we use the L-Index model to quantitatively evaluate the vertical and regional distributions of the macrolithotypes of No. 3 coal seam in Zhengzhuang field, southern Qinshui basin. Moreover, we also proposed a S-Index model to quantitatively evaluate the general brightness of a whole coal seam: the increase of the S-Index from 1 to 3.7, indicates decreasing brightness, i.e., from bright coal to dull coal. Finally, we discussed the relationship between S-Index and the hydro-fracturing effect. It was found that the coal seam with low S-Index values can easily form long extending fractures during hydraulic fracturing. Therefore, the lower S-Index values indicate much more favorable gas production potential in the Zhengzhuang field. This study provides a new methodology to evaluate coal macrolithotypes by using geophysical logging data.

Sign in / Sign up

Export Citation Format

Share Document