scholarly journals Evaluation of CO2 Storage in a Shale Gas Reservoir Compared to a Deep Saline Aquifer in the Ordos Basin of China

Energies ◽  
2020 ◽  
Vol 13 (13) ◽  
pp. 3397
Author(s):  
Danqing Liu ◽  
Yilian Li ◽  
Ramesh Agarwal
Keyword(s):  
High Speed ◽  
Co2 Storage ◽  
Ordos Basin ◽  
Co2 Injection ◽  
Saline Aquifer ◽  
Pressure Perturbation ◽  
Deep Saline Aquifer ◽  
The Ordos Basin ◽  
Shale Reservoir ◽  
Continuous Injection

As a new “sink” of CO2 permanent storage, the depleted shale reservoir is very promising compared to the deep saline aquifer. To provide a greater understanding of the benefits of CO2 storage in a shale reservoir, a comparative study is conducted by establishing the full-mechanism model, including the hydrodynamic trapping, adsorption trapping, residual trapping, solubility trapping as well as the mineral trapping corresponding to the typical shale and deep saline aquifer parameters from the Ordos basin in China. The results show that CO2 storage in the depleted shale reservoir has merits in storage safety by trapping more CO2 in stable immobile phase due to adsorption and having gentler and ephemeral pressure perturbation responding to CO2 injection. The effect of various CO2 injection schemes, namely the high-speed continuous injection, low-speed continuous injection, huff-n-puff injection and water alternative injection, on the phase transformation of CO2 in a shale reservoir and CO2-injection-induced perturbations in formation pressure are also examined. With the aim of increasing the fraction of immobile CO2 while maintaining a safe pressure-perturbation, it is shown that an intermittent injection procedure with multiple slugs of hug-n-puff injection can be employed and within the allowable range of pressure increase, and the CO2 injection rate can be maximized to increase the CO2 storage capacity and security in shale reservoir.

scholarly journals Numerical Simulation and Optimization of CO2 Sequestration in Saline Aquifers

2012 ◽  
Author(s):  
Zheming Zhang ◽  
Ramesh Agarwal
Keyword(s):  
Numerical Simulation ◽  
Co2 Sequestration ◽  
Storage Capacity ◽  
Co2 Storage ◽  
Injection Well ◽  
Co2 Injection ◽  
Great Promise ◽  
Saline Aquifer ◽  
Simulation And Optimization ◽  
Co2 Plume

With recent concerns on CO2 emissions from coal fired electricity generation plants; there has been major emphasis on the development of safe and economical Carbon Dioxide Capture and Sequestration (CCS) technology worldwide. Saline reservoirs are attractive geological sites for CO2 sequestration because of their huge capacity for sequestration. Over the last decade, numerical simulation codes have been developed in U.S, Europe and Japan to determine a priori the CO2 storage capacity of a saline aquifer and provide risk assessment with reasonable confidence before the actual deployment of CO2 sequestration can proceed with enormous investment. In U.S, TOUGH2 numerical simulator has been widely used for this purpose. However at present it does not have the capability to determine optimal parameters such as injection rate, injection pressure, injection depth for vertical and horizontal wells etc. for optimization of the CO2 storage capacity and for minimizing the leakage potential by confining the plume migration. This paper describes the development of a “Genetic Algorithm (GA)” based optimizer for TOUGH2 that can be used by the industry with good confidence to optimize the CO2 storage capacity in a saline aquifer of interest. This new code including the TOUGH2 and the GA optimizer is designated as “GATOUGH2”. It has been validated by conducting simulations of three widely used benchmark problems by the CCS researchers worldwide: (a) Study of CO2 plume evolution and leakage through an abandoned well, (b) Study of enhanced CH4 recovery in combination with CO2 storage in depleted gas reservoirs, and (c) Study of CO2 injection into a heterogeneous geological formation. Our results of these simulations are in excellent agreement with those of other researchers obtained with different codes. The validated code has been employed to optimize the proposed water-alternating-gas (WAG) injection scheme for (a) a vertical CO2 injection well and (b) a horizontal CO2 injection well, for optimizing the CO2 sequestration capacity of an aquifer. These optimized calculations are compared with the brute force nearly optimized results obtained by performing a large number of calculations. These comparisons demonstrate the significant efficiency and accuracy of GATOUGH2 as an optimizer for TOUGH2. This capability holds a great promise in studying a host of other problems in CO2 sequestration such as how to optimally accelerate the capillary trapping, accelerate the dissolution of CO2 in water or brine, and immobilize the CO2 plume.

Investigation of CO2–CH4 Displacement and Transport in Shale for Enhanced Shale Gas Recovery and CO2 Sequestration

2016 ◽  
Vol 139 (1) ◽  
Author(s):  
Xi-Dong Du ◽  
Min Gu ◽  
Shuo Duan ◽  
Xue-Fu Xian
Keyword(s):  
Shale Gas ◽  
Co2 Storage ◽  
Fixed Bed ◽  
Co2 Injection ◽  
Gas Reservoir ◽  
Co2 Gas ◽  
Gas Recovery ◽  
Shale Gas Reservoir ◽  
Shale Reservoir ◽  
Adsorption Amount

To gain a better understanding of the enhanced shale gas recovery by CO2 gas injection (CO2-ESGR) technique, the dynamic displacement mechanism of CO2–CH4, the CO2 enhanced shale gas recovery (RCH4), and CO2 storage capacity (VCO2) were studied based on transport properties of CO2 and CH4. Experiments of CO2 injection into shale gas reservoir preadsorbed by CH4 were performed in a fixed bed. Breakthrough curves were obtained under different test conditions and simulated by one-dimension advection-dispersion (AD) model. It was found that dispersion coefficient (K1) rather than molecular diffusivity of CO2 dominated its transport in shale. K1 together with advection velocity (υ) of CO2 during CH4 displacement controls RCH4 and VCO2. When transporting in shale gas reservoir, CO2 had larger dynamic adsorption amount and υ, but smaller K1 than CH4. The competitive transport and adsorption behavior of CO2 and CH4 made it possible for CO2 to store in shale reservoir and to drive the in-place CH4 out of shale reservoir. The transfer zone of CO2–CH4 displacement (CCD) was very wide. High RCH4 and VCO2 were reached at low injection CO2 gas pressure and for small shale particles. Higher injection flow rates of CO2 and temperatures ranging from 298 K to 338 K had a little effect on RCH4 and VCO2. For field conditions, high CO2 injection pressure has to be used because the pore pressure of shale reservoir and adsorption amount of CH4 increase with the increase in depth of shale gas reservoir, but RCH4 is still not high.

Sign in / Sign up

Export Citation Format

Share Document