Effects of Imbibition and Compaction during Well Shut-In on Ultimate Shale Oil Recovery: A Numerical Study

2021 ◽  
pp. 1-15
Author(s):  
Nur Wijaya ◽  
James Sheng
Keyword(s):  
Hydraulic Fracturing ◽  
Oil Recovery ◽  
Net Present Value ◽  
Numerical Study ◽  
Extended Period ◽  
Strong Relationship ◽  
Shale Oil ◽  
Probabilistic Forecasting ◽  
Driving Mechanisms ◽  
Reservoir Conditions

Summary Shale wells are often shut in after hydraulic fracturing is completed. Shut-in often lasts for an extended period in the perceived hope of improving the ultimate oil recovery. However, current literature does not show a strong consensus on whether shut-in will improve ultimate oil recovery. Because of the delayed production, evaluating the benefits of shut-in in improving the ultimate oil recovery is crucial. Otherwise, shut-in would merely delay the production and harm the economic performance. In this paper, we use a numerical flow-geomechanical modeling approach to investigate the effect of imbibition on shut-in potentials to improve the ultimate oil recovery. We propose that imbibition is one of the strongly confounding variables that causes mixed conclusions in the related literature. The investigation methodology involves probabilistic forecasting of three reservoir realization models validated based on the same field production data. Each of the models represents different primary recovery-driving mechanisms, such as imbibition-dominant and compaction-dominantrecovery. A parametric study is conducted to explore and identify the specific reservoir conditions in which shut-in tends to improve shale oil recovery. Ten reservoir parameters that affect the imbibition strength are studied under different shut-in durations. Comparison among the three models quantitatively demonstrates that shut-in tends to improve both the ultimate oil recovery and net present value (NPV) only if the shale reservoir demonstrates imbibition-dominant recovery. A correlation among ultimate oil recovery, flowback efficiency, and NPV also shows that there is no strong relationship between flowback efficiency and ultimate oil recovery. This study is one of the first to emphasize the importance of quantifying the imbibition strength and its contribution in helping recover the shale oil for optimum flowback and shale well shut-in design after hydraulic fracturing.

Effects of Imbibition During Well Shut-In on Ultimate Shale Oil Recovery: A Numerical Study

2021 ◽  
Author(s):  
Nur Wijaya ◽  
James Sheng
Keyword(s):  
Hydraulic Fracturing ◽  
Oil Recovery ◽  
Numerical Study ◽  
Extended Period ◽  
Strong Relationship ◽  
Driving Mechanism ◽  
Shale Oil ◽  
Probabilistic Forecasting ◽  
Reservoir Conditions ◽  
Shale Oil Reservoirs

Abstract Shale wells are often shut-in after hydraulic fracturing is finished. Shut-in often lasts for an extended period in the perceived hope to improve the ultimate oil recovery. However, current literature does not show a strong consensus on whether shut-in will improve the ultimate oil recovery. Because of the delayed production, evaluating the benefits of shut-in in improving the ultimate oil recovery is crucial. Otherwise, shut-in would merely delay the production and harm the economic performance. This paper uses a numerical flow-geomechanical modeling approach to investigate the effect of imbibition on shut-in potentials to improve the ultimate oil recovery. This paper proposes that imbibition is one of the strongly confounding variables that cause the mixed conclusions in the related literature. The investigation methodology involves probabilistic forecasting of three reservoir realization models validated based on the same field production data. Each of the models represents different primary recovery driving mechanism, such as imbibition-dominant and compaction-dominant recovery. A parametric study is conducted to explore and identify the specific reservoir conditions in which shut-in tends to improve the shale oil recovery. Ten reservoir parameters which affect the imbibition strength are studied under different shut-in durations. Comparison among the three models quantitatively demonstrates that shut-in tends to improve the ultimate oil recovery only if the shale reservoir demonstrates imbibition-dominant recovery. A first-pass economic analysis also suggests that when the shale oil reservoirs demonstrate such an imbibition-dominant recovery, shut-in tends to not only improve the ultimate oil recovery, but also the NPV. A correlation among ultimate oil recovery, flowback efficiency, and NPV also shows that there is no strong relationship between flowback efficiency and ultimate oil recovery. This study is one of the first to emphasize the importance of quantifying the imbibition strength and its contribution in helping recover the shale oil for optimum flowback framework and shale well shut-in design after hydraulic fracturing.

scholarly journals Compositional Modeling for Optimum Design of Water-Alternating CO2-LPG EOR under Complicated Wettability Conditions

2015 ◽  
Vol 2015 ◽  
pp. 1-9 ◽  
Author(s):  
Jinhyung Cho ◽  
Sung Soo Park ◽  
Moon Sik Jeong ◽  
Kun Sang Lee
Keyword(s):  
Interfacial Tension ◽  
Mole Fraction ◽  
Oil Recovery ◽  
Net Present Value ◽  
Numerical Study ◽  
Present Value ◽  
Compositional Simulation ◽  
Maximum Enhancement ◽  
Tension Reduction ◽  
Improved Oil Recovery

The addition of LPG to the CO2stream leads to minimum miscible pressure (MMP) reduction that causes more oil swelling and interfacial tension reduction compared to CO2EOR, resulting in improved oil recovery. Numerical study based on compositional simulation has been performed to examine the injectivity efficiency and transport behavior of water-alternating CO2-LPG EOR. Based on oil, CO2, and LPG prices, optimum LPG concentration and composition were designed for different wettability conditions. Results from this study indicate how injected LPG mole fraction and butane content in LPG affect lowering of interfacial tension. Interfacial tension reduction by supplement of LPG components leads to miscible condition causing more enhanced oil recovery. The maximum enhancement of oil recovery for oil-wet reservoir is 50% which is greater than 22% for water-wet reservoir. According to the result of net present value (NPV) analysis at designated oil, CO2, propane, and butane prices, the optimal injected LPG mole fraction and composition exist for maximum NPV. At the case of maximum NPV for oil-wet reservoir, the LPG fraction is about 25% in which compositions of propane and butane are 37% and 63%, respectively. For water-wet reservoir, the LPG fraction is 20% and compositions of propane and butane are 0% and 100%.

Experimental and Numerical Study on CO2 Sweep Volume during CO2 Huff-n-Puff Enhanced Oil Recovery Process in Shale Oil Reservoirs

2019 ◽  
Vol 33 (5) ◽  
pp. 4017-4032 ◽  
Author(s):  
Lei Li ◽  
Yuliang Su ◽  
James J. Sheng ◽  
Yongmao Hao ◽  
Wendong Wang ◽  
...  
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Numerical Study ◽  
Recovery Process ◽  
Oil Reservoirs ◽  
Shale Oil ◽  
Shale Oil Reservoirs

scholarly journals Optimization of engineered water injection performance in heterogeneous carbonates: a numerical study on a sector model

2020 ◽  
Vol 10 (8) ◽  
pp. 3803-3826
Author(s):  
Jamiu Oyekan Adegbite ◽  
Emad Walid Al-Shalabi
Keyword(s):  
Sensitivity Analysis ◽  
Oil Recovery ◽  
Net Present Value ◽  
Numerical Study ◽  
Water Injection ◽  
Design Parameters ◽  
Present Value ◽  
Tax Rate ◽  
Sector Model ◽  
Evolution Algorithms

Abstract One of the emerging technologies for boosting oil recovery in both sandstone and carbonate reservoirs is engineered/low-salinity water injection (EWI/LSWI). In this paper, optimization of engineered water injection is investigated using three synthetic sector models representing homogeneous, heterogeneous with channeling, and heterogeneous with gravity underride reservoirs. Both oil recovery and net present value were investigated as objective functions for the study. Eighteen design parameters were selected for the study including reservoir, operational, and economic parameters. Response Surface Methodology and Designed Exploration and Controlled Evolution algorithms were implemented for sensitivity analysis and optimization studies, respectively. The study highlighted that NPV is more representative as an objective function compared to oil recovery where the three optimized models have about similar oil recovery, but different NPVs. The sensitivity analysis showed that oil price, tax rate, and initial oil saturation are the three most influential design parameters on the net present value for the three models investigated. Moreover, the findings showed that developing the gravity underride model requires more attention as being the most sensitive model with 13 influential design parameters. The optimization study highlighted that secondary EWI is recommended to achieve the best profitability out of the three models. However, a high maximum exposure is expected due to the capital and operational costs related to early EWI application. This study is one of the very few that discusses the economic aspect of EWI while incorporating the complexity of geochemical reactions and the heterogeneity of carbonates.

scholarly journals Simulation Analysis of CO2-EOR Process and Feasibility of CO2 Storage during EOR

Energies ◽  
2021 ◽  
Vol 14 (4) ◽  
pp. 1154
Author(s):  
Maja Arnaut ◽  
Domagoj Vulin ◽  
Gabriela José García Lamberg ◽  
Lucija Jukić
Keyword(s):  
Oil Recovery ◽  
Reservoir Simulation ◽  
Net Present Value ◽  
Simulation Analysis ◽  
Co2 Storage ◽  
Oil Production ◽  
Utilization Factor ◽  
Reservoir Conditions ◽  
Multiparameter Analysis ◽  
The Impact

In this study, oil production and retention were observed and compared in 72 reservoir simulation cases, after which an economic analysis for various CO2 and oil prices was performed. Reservoir simulation cases comprise different combinations of water alternating gas (WAG) ratios, permeabilities, and well distances. These models were set at three different depths; thus different pressure and temperature conditions, to see the impact of miscibility on oil production and CO2 sequestration. Those reservoir conditions affect oil production and CO2 retention differently. The retention trend dependence on depth was not monotonic—optimal retention relative to the amount of injected CO2 could be achieved at middle depths and mediocre permeability as well. Results reflecting different reservoir conditions and injection strategies are shown, and analysis including the utilization factor and the net present value was conducted to examine the feasibility of different scenarios. The analysis presented in this paper can serve as a guideline for multiparameter analysis and optimization of CO2-enhanced oil recovery (EOR) with a WAG injection strategy.

scholarly journals Experimental study of the supercritical CO 2 diffusion coefficient in porous media under reservoir conditions

2019 ◽  
Vol 6 (6) ◽  
pp. 181902 ◽  
Author(s):  
Junchen Lv ◽  
Yuan Chi ◽  
Changzhong Zhao ◽  
Yi Zhang ◽  
Hailin Mu
Keyword(s):  
Porous Media ◽  
Diffusion Coefficient ◽  
Oil Recovery ◽  
Carbon Capture ◽  
Carbon Capture And Storage ◽  
Elevated Pressure ◽  
Experimental Results ◽  
Saturated Porous Media ◽  
Reservoir Conditions ◽  
The Impact

Reliable measurement of the CO 2 diffusion coefficient in consolidated oil-saturated porous media is critical for the design and performance of CO 2 -enhanced oil recovery (EOR) and carbon capture and storage (CCS) projects. A thorough experimental investigation of the supercritical CO 2 diffusion in n -decane-saturated Berea cores with permeabilities of 50 and 100 mD was conducted in this study at elevated pressure (10–25 MPa) and temperature (333.15–373.15 K), which simulated actual reservoir conditions. The supercritical CO 2 diffusion coefficients in the Berea cores were calculated by a model appropriate for diffusion in porous media based on Fick's Law. The results show that the supercritical CO 2 diffusion coefficient increases as the pressure, temperature and permeability increase. The supercritical CO 2 diffusion coefficient first increases slowly at 10 MPa and then grows significantly with increasing pressure. The impact of the pressure decreases at elevated temperature. The effect of permeability remains steady despite the temperature change during the experiments. The effect of gas state and porous media on the supercritical CO 2 diffusion coefficient was further discussed by comparing the results of this study with previous study. Based on the experimental results, an empirical correlation for supercritical CO 2 diffusion coefficient in n -decane-saturated porous media was developed. The experimental results contribute to the study of supercritical CO 2 diffusion in compact porous media.

scholarly journals Performance Evaluation of Enzyme Breaker for Fracturing Applications under Simulated Reservoir Conditions

Molecules ◽  
2021 ◽  
Vol 26 (11) ◽  
pp. 3133
Author(s):  
Yuling Meng ◽  
Fei Zhao ◽  
Xianwei Jin ◽  
Yun Feng ◽  
Gangzheng Sun ◽  
...  
Keyword(s):  
Hydraulic Fracturing ◽  
Shear Resistance ◽  
Ammonium Persulfate ◽  
Fracturing Fluid ◽  
Medium Temperature ◽  
Fracture Conductivity ◽  
Wide Range ◽  
Reservoir Conditions ◽  
Alkaline Conditions ◽  
Resistance Performance

Fracturing fluids are being increasingly used for viscosity development and proppant transport during hydraulic fracturing operations. Furthermore, the breaker is an important additive in fracturing fluid to extensively degrade the polymer mass after fracturing operations, thereby maximizing fracture conductivity and minimizing residual damaging materials. In this study, the efficacy of different enzyme breakers was examined in alkaline and medium-temperature reservoirs. The parameters considered were the effect of the breaker on shear resistance performance and sand-suspending performance of the fracturing fluid, its damage to the reservoir after gel breaking, and its gel-breaking efficiency. The experimental results verified that mannanase II is an enzyme breaker with excellent gel-breaking performance at medium temperatures and alkaline conditions. In addition, mannanase II did not adversely affect the shear resistance performance and sand-suspending performance of the fracturing fluid during hydraulic fracturing. For the same gel-breaking result, the concentration of mannanase II used was only one fifth of other enzyme breakers (e.g., mannanase I, galactosidase, and amylase). Moreover, the amount of residue and the particle size of the residues generated were also significantly lower than those of the ammonium persulfate breaker. Finally, we also examined the viscosity-reducing capability of mannanase II under a wide range of temperatures (104–158 °F) and pH values (7–8.5) to recommend its best-use concentrations under different fracturing conditions. The mannanase has potential for applications in low-permeability oilfield development and to maximize long-term productivity from unconventional oilwells.

Potential of dimethyl ether as an additive in CO2 for shale oil recovery

Fuel ◽  
2021 ◽  
Vol 296 ◽  
pp. 120643
Author(s):  
Shaoqi Kong ◽  
Gan Feng ◽  
Yueliang Liu ◽  
Kunjie Li
Keyword(s):  
Dimethyl Ether ◽  
Oil Recovery ◽  
Shale Oil
Sign in / Sign up

Export Citation Format

Share Document