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Collaborating Authors
University of Regina
Quantification of Phase Behaviour and Physical Properties of n-Alkane Solvents/Water/Athabasca Bitumen Mixtures Under Reservoir Conditions
Huang, Desheng (University of Regina) | Li, Yunlong (University of Regina) | Dong, Xiaomeng (University of Regina) | Yang, Daoyong (University of Regina)
Abstract Experimental and theoretical techniques have been developed to quantify phase behaviour and physical properties in terms of phase boundaries, swelling factors, phase volumes, and phase compositions. Experimentally, five sets of PVT experiments of pentane, hexane, and heptane, respectively, mixed with bitumen have been conducted to measure phase behaviour data in the absence and presence of water by using a conventional PVT setup at elevated temperatures up to 438.2 K. Theoretically, the Athabasca bitumen is characterized as four pseudocomponents, while the binary interaction parameters (BIPs) are optimized by reproducing the measured saturation pressures. The original Peng-Robinson equation of state (PR EOS) has been advanced to perform flash calculations by incorporating a recently modified alpha function and an improved volume translation method together with the Huron-Vidal mixing rule, while the results have been compared with those obtained from CMG WinProp module incorporated with the original alpha function as well as default and optimized BIP correlations. It is from the experimental observation that the saturation pressures of n-alkane solvents/water/bitumen mixtures are decreased with carbon numbers at the same conditions. Also, the saturation pressures of n-alkane solvents/bitumen mixtures are increased with the addition of water because water molecules are evaporated into vapour phase at relatively low pressure and high temperature conditions. The BIPs of pure solvent/bitumen pairs, which are optimized through fitting the measured saturation pressures, work well for n-alkanes/bitumen mixtures in the absence and presence of water. Such an advanced PR EOS (APR EOS) model can accurately reproduce the experimentally obtained multiphase boundaries, swelling factors, phase volumes and compositions with an average absolute relative derivation (AARD) of 7.82%, 2.11%, 6.78%, and 4.38%, respectively, indicating that it can provide fundamental data for the design and optimization of the hybrid solvent-steam recovery method for bitumen resources.
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Steam-solvent combination methods (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
- Facilities Design, Construction and Operation > Unconventional Production Facilities > Oil sand/shale/bitumen (1.00)
Modeling Two-Phase Flow Behaviour in a Shale Gas Reservoir with Complex Fracture Networks and Flow Dynamics
Zhang, Yunhao (University of Regina) | Yang, Daoyong (University of Regina)
Abstract In this work, a robust and pragmatic method has been developed, validated, and applied to describe two-phase flow behaviour of a multifractured horizontal well (MFHW) in a shale gas formation. As for a fracture subsystem, its permeability modulus, non-Darcy flow coefficient, and slippage factor have been defined and embedded into the governing equation, while an iterative method is applied to update the gas/water saturation in each fracture segment within discrete fracture networks. For a matrix subsystem, a skin factor on a fracture face is defined and introduced to represent the change in relative permeability in the matrix domain at each timestep, while the adsorption/desorption term is incorporated into the diffusivity equation to accurately calculate the shale gas production by taking the adsorbed gas in nanoscale porous media into account. Then, the theoretical model can be applied to accurately capture the two-phase flow behaviour in different subdomains. The accuracy of this newly developed model has been confirmed by the numerical simulation and then it is extended to field applications with excellent performance. The stress-sensitivity, non-Darcy flow, and slippage effect in a hydraulic fracture (HF) are found to be obvious during the production, while the initial gas saturation in a matrix and HFs imposes an evident influence on the production profile. As for an HF with a high gas saturation, the dewatering stage is missing and water from the matrix can be neglected during a short production time. For the matrix subsystem, a high-water saturation in the matrix near an HF can affect gas production during the entire stage as long as gas relative permeability in the HF remains low. In addition, the adsorption/desorption in the matrix subsystem can increase gas production but decrease water production. Compared to the observed gas/water production rates for field applications, the solutions obtained from the method in this work are found to be well matched, confirming its reliability and robustness.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Geological Subdiscipline > Geomechanics (0.93)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
Influence of Hydrogen Sulfide on Adsorption Behavior of CO2/CH4 Mixtures in Calcite Nanopores with the Implications for CO2 Sequestration
Qian, Cheng (China University of Petroleum, Beijing) | Rui, Zhenhua (China University of Petroleum, Beijing) | Liu, Yueliang (China University of Petroleum, Beijing) | Zhao, Yang (China University of Petroleum, Beijing) | Li, Huazhou Andy (University of Alberta) | Ma, An (Moscow State University) | Afanasyev, Andrey (Moscow State University) | Torabi, Farshid (University of Regina)
Abstract Injecting CO2 into reservoirs for storage and enhanced oil recovery (EOR) is a practical and cost-effective strategy for achieving carbon neutrality. Commonly, CO2-rich industrial waste gas is employed as the CO2 source, whereas contaminants such as H2S may severely impact carbon storage and EOR via competitive adsorption. Hence, the adsorption behavior of CH4, CO2, and H2S in calcite (CaCO3) micropores and the impact of H2S on CO2 sequestration and methane recovery are specifically investigated using molecular simulation. The Grand Canonical Monte Carlo (GCMC) simulations were applied to study the adsorption characteristics of pure CO2, CH4, and H2S, and their multi-component mixtures are also investigated in calcite nanopores to reveal the impact of H2S on CO2 storage. The effect of pressure (0-20 MPa), temperature (293.15-383.15 K), pore width, buried depth and gas mole fraction on the adsorption behaviors are simulated. Molecular dynamics simulations (MD) were performed to explore the diffusion characteristics of the three gases and their mixes. The amount of adsorbed CH4, CO2, and H2S enhances with rising pressure and declines with rising temperature. The order of adsorption quantity in calcite nanopores is H2S>CO2>CH4, whereas the order of adsorption strength between the three gases and calcite is CO2>H2S>CH4 based on the interaction energy analysis. At 10 MPa and 3215 K, the interaction energies of calcite with CO2, H2S, and CH4 are -2166.40, -2076.93, and -174.57 kcal/mol, respectively. The CH4-calcite and H2S-calcite interaction energies are dominated by van der Waals energy, whereas electrostatic energy predominates in the CO2-calcite system. The adsorption loading of CH4 and CO2 are lowered by approximately 59.47% and 24.82% when the mole fraction of H2S is 20% at 323.15 K, reflecting the weakening of CH4 and CO2 adsorption by H2S due to competitive adsorption. The diffusivities of three pure gases in calcite nanopore are listed in the following order: CO2 > H2S > CH4. The presence of H2S in the ternary mixtures will limit diffusion and outflow of the system and each component gas, with CH4 being the gas most affected by H2S. The CO2/CH4 mixture can be buried in formations as shallow as 1000-1500 m, but the ternary mixture should be stored in deeper formations. The effects of H2S on CO2 sequestration and CH4 recovery in calcite nanopores are clarified, which provides theoretical assistance for CO2 storage and EOR projects in carbonate formation.
- Asia > China (0.29)
- North America > United States (0.28)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Health, Safety, Environment & Sustainability > Health > Noise, chemicals, and other workplace hazards (1.00)
A New Experimental Core Analysis Method for Formation Permeability Measurement Under Two-Phase Condition
Zhang, Fengyuan (China University of Petroleum, Beijing) | Zhang, Qiang (China University of Petroleum, Beijing) | Zhang, Zhengxin (China University of Petroleum, Beijing) | Rui, Zhenhua (China University of Petroleum, Beijing) | Liu, Yueliang (China University of Petroleum, Beijing) | Zhang, Wei (University of Calgary) | Zheng, Xiaojin (Princeton University) | Torabi, Farshid (University of Regina) | Afanasyev, Andrey (Moscow State University)
Abstract Experimental methods for core plug analysis are widely used to measure formation permeability under steady-state flow or unsteady state flow conditions, which provides important geoscience information on formation properties. However, typical laboratory techniques hardly reproduce the two-phase water and hydrocarbon storage and transport conditions that formation is subject to in reality. Accordingly, we presented an integrated experimental core analysis method for permeability measurement, which better reproduces these two-phase conditions. The proposed experimental method consists of two-phase fluid initialization and production test, during which the gas rate, liquid rate, and inlet/outlet pressure of the core plug are recorded simultaneously. After constructing with uniform distribution of gas and liquid, the core sample is transformed into a two-phase production process under the conditions of variable rate and sealed boundary. Rate transient analysis is performed to estimate formation permeability with the gathered two-phase rate decline and pressure data. A two-phase diagnostic plot and specialty plot are introduced to identify flow regimes and extract permeability from the slope of a straight line during the experimental data analysis. In this paper, commercial software is used to generate synthetic data for the production test of a core plug. The simulation of two-phase fluid initialization and production tests were conducted on core plugs. The simulation results show a unit-slope straight line on the generated diagnostic plot, which indicates a clear boundary-dominated flow (BDF) regime. By performing a straight-line analysis, we calculated the permeability of the core plug with the slope of straight-line period on specialty plot. The good match of the calculated permeability with the reference value confirms the accuracy of the proposed experimental method with the relative error less than 10%. In addition, the proposed two-phase core analysis method can enormously accelerate test-time, as the permeability of selected rock sample can be estimated in less than 10 minutes. Instead of measuring permeability only under the condition of single phase flow, this paper presents a laboratory technique that combines the experiment of small-diameter core production test under two-phase flow with rate transient analysis method. Unlike prior experimental techniques, the proposed method reproduces the more realistic condition of two-phase flow in the formation during permeability measurement. The two-phase core analysis method achieves the objective of accurate and fast characterization of formation permeability, which is a more "apples to apples" comparison between the fluid flow in the actual reservoir and the core plug.
- North America > United States > Texas (0.28)
- Europe > Norway > Norwegian Sea (0.24)
- Research Report > New Finding (0.48)
- Research Report > Experimental Study (0.34)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.69)
- Geology > Mineral (0.68)
- Geology > Geological Subdiscipline > Geomechanics (0.68)
- Asia > China > Sichuan > Sichuan Basin (0.99)
- Asia > China > Shanxi > Ordos Basin (0.99)
- Asia > China > Shaanxi > Ordos Basin (0.99)
- Asia > China > Gansu > Ordos Basin (0.99)
Field-Scale Modeling of Interwell Tracer Flow Behaviour to Characterize Complex Fracture Networks Based on the Embedded Discrete Fracture Model in a Naturally Fractured Reservoir
Liu, Jinju (University of Regina) | Jiang, Liwu (University of Regina) | Liu, Tongjing (China University of Petroleum, Beijing) | Yang, Daoyong (University of Regina)
Abstract In this study, the newly proposed numerical models have been verified and used to characterize the fracture distributions in a naturally fractured reservoir conditioned to tracer transport behaviour. The stochastic fracture modeling approach is implemented to generate the randomly-distributed natural fractures which are dealt with the embedded discrete fracture model (EDFM) while ensuring its sufficient accuracy. To be specific, the matrix domain is discretized using the structured grids, within which each embedded fracture is divided into a series of segments. Subsequently, non-neighbouring connections allow us to couple the flow of fluid and tracer between the non-neighbouring grid cells, while the historical tracer profiles are matched to delineate the geometry and properties of the fractures by taking multiple tracer transport mechanisms into account. Furthermore, the influences of fracture number, fracture length, fracture orientation, and tracer dispersion on the tracer production concentration have been investigated through sensitivity analysis. The response of an interwell tracer model is sensitive to the fracture parameters rather than tracer properties. A fracture network with its orientation parallel to the mainstream direction will cause the earliest tracer breakthrough. The tracer breakthrough time with an average fracture length equal to 40 m is 110 days earlier than that with a mean fracture length value of 10 m, while the tracer production peak concentration for the former is nearly two times higher than for the latter. A larger fracture number results in an earlier tracer breakthrough and an intermediate fracture number will lead to the highest tracer production concentration. Additionally, the newly developed model has been validated through its comparison with the commercial ECLIPSE simulator and then extended to field applications to identify the possible fracture distributions by simulating multi-well tracer tests in the Midale field. The flexible and pragmatic EDFM-based method developed in this study can model the interwell tracer flow behaviour as well as characterize the properties and geometries of the natural fractures with better performance on accuracy and calculation efficiency in comparison with other fracture simulation methods (e.g., local grid refinement (LGR) method).
- North America > Canada (1.00)
- Asia (1.00)
- North America > United States > Texas (0.93)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.93)
- Geology > Geological Subdiscipline > Geomechanics (0.93)
Feasibility of Carbon Storage in Kirby Depleted Shallow Gas Fields: A Numerical and Statistical Analysis
Peng, Xiaolong (Geological Survey of Canada Calgary) | Chen, Zhuoheng (Geological Survey of Canada Calgary) | Zeng, Fanhua (University of Regina) | Yuan, Wanju (Geological Survey of Canada Calgary) | Yao, Jiangyuan (Geological Survey of Canada Calgary) | Hu, Kezhen (Geological Survey of Canada Calgary)
Abstract The current screening criteria excluded shallow formations (depth < 800 m) from the desirable CO2 geological storage sites. However, in the Athabasca oil sands area of northeast Alberta, shallow gas reservoirs have at least 500 Mt storage potential and are close to many large emitters in Alberta. This study uses Kirby gas fields as an example and examines the suitability of shallow gas reservoirs as CO2 storage sites from leaking risks associated with engineering aspects. First, the storage systems characterized by five parameters were built based on a statistical analysis of 210 gas pools in the Kirby field. Second, to capture uncertainties, 270 cases were simulated to represent the sealing-layer performances. The results were then analyzed statistically, where an information-entropy-based regression tree was generated to rank the relative importance of the parameters and leaking risk level. Third, the storage systems with multi-sealing layers were modeled to examine the effective drainage area, injectivity, and storage capacity under different drilling and injection schemes. Finally, the potential issues of carbon storage in depleted shallow gas fields were addressed. Our study suggests that the CO2 storage potential and carbon-neutral benefits of the shallow gas reservoir in the Athabasca oil sands area are underestimated for the low-carbon energy transition. The results found that the regression tree allows for screening parameters effectively for selecting storage sites from the shallow gas pools and revealed that the permeability of the sealing layers is more important than the seal thickness. For CO2 storage in shallow formations, the minimum requirements of the seal (especially for the caprock) under the safe injection pressure range are a permeability of less than 0.001 mD and a thickness higher than 35 m. Due to key characteristics of shallow gas reservoirs (high permeability and thin reservoir layers), the CO2 plume behaviors are significantly different from reported CO2 storages in desirable deep formations. The CO2 plume will spread rapidly in all directions of the reservoirs and reaches the maximum capacity quickly. A low well density of the CO2 injection network (< 0.39 wells/km) is sufficient for CO2 storage in shallow depleted gas reservoirs. Compared to the single-layer injection scheme, the multi-layer injection can relieve the early leaking risks of the mid-sealing layers and increase the injection rate to nearly 1 Mt CO2 per year. The short project life resulting from the high injection rate and small storage capacity in each gas pool makes the CCS projects of shallow reservoirs in NE Alberta more suitable for transporting CO2 using tankers or repurposing the old pipelines nearby. It also makes the small (~64.7 E4m) to medium gas reservoirs (259 E4m) with excellent top seals the desirable candidates of CO2 storage for small companies when the carbon tax reaches $170/ton in 2030. A novel workflow with an effective assessment methodology for selecting CO2 storage sites from shallow gas pools has been proposed. The results can assist geoscientists in reducing uncertainty on the estimate of CO2 capacity storage and provide practical guidance on site selection for the pre-feasibility study of CO2 storage in shallow formations.
- Research Report > New Finding (0.48)
- Research Report > Experimental Study (0.34)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Geological Subdiscipline > Geomechanics (0.68)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.31)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Health, Safety, Environment & Sustainability > Sustainability/Social Responsibility > Sustainable development (1.00)
- (2 more...)
A Review-Dissolution and Mineralization Storage of CO2 Geological Storage in Saline Aquifers
Wang, Bo (University of Regina) | Wang, Xiangzeng (Shaanxi Yanchang Petroleum Co Ltd) | Chen, Yiming (University of Regina) | Liang, Quansheng (Shaanxi Yanchang Petroleum Co Ltd) | Zeng, Fanhua (University of Regina)
Abstract Saline aquifer has become the preferred storage location of carbon capture, and storage (CCS) technology because of its wide distribution, large storage capacity and high safety factor. According to IPCC statistics, the storage capacity of saline aquifers worldwide is 400 – 10000 Gt, which is dozens of times that of oil and gas reservoirs and hundreds of times that of coal seams. Therefore, the carbon storage in saline aquifer has the most potential for CO2 storage. Carbon sequestration in saline aquifers includes four trapping mechanisms: short-term geological and hydrodynamic capture and long-term geochemical (solubility and mineral) capture. Moreover, the solubility of CO2 in saline aquifer and the mechanism of mineral capture (salt precipitation) depends on the injected CO2 and the water-rock characteristics of saline aquifer. However, current knowledge on geochemical capture is still at an early stage compared to other capture theories. Recent researches indicate that although temperature, pressure, salinity of formation water and mineral composition of formation rocks are important factors affecting mineral storage, other reservoir parameters, such as reservoir thickness, dip angle, anisotropy, and bedding distribution, may also significantly affect salt precipitation, mineral storage, and geo-chemical storage. In this paper, we would like to present a comprehensive review on the solubility model of CO2 in saline aquifers, the phase permeability change of CO2 and saline aquifers, the mechanism of CO2-water -rock interaction, the dissolution and precipitation model of inorganic salt minerals, and the influencing factors for CO2 sequestration in saline aquifers. We believe that this review lays a foundation for future study of carbon storage technology in saline aquifer.
- Europe > United Kingdom (1.00)
- Asia (1.00)
- North America > Canada > Alberta (0.46)
- North America > United States > California (0.28)
- Research Report > New Finding (1.00)
- Overview (1.00)
- Geology > Rock Type > Igneous Rock (1.00)
- Geology > Mineral > Silicate (1.00)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- (2 more...)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.68)
- North America > United States > Wyoming > Big Horn Basin > NPR-3 > Tensleep Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Johns Field (0.99)
- North America > United States > South Dakota > Williston Basin (0.99)
- (17 more...)
Geomechanical Investigation of Caprock Integrity of Potential CO2 Storage Reservoirs in Lloydminster Area
Shen, Chen (University of Regina) | Wang, Bo (University of Regina) | Azadbakht, Saman (University of Regina) | Hawkes, Christopher (University of Saskatchewan) | Zhang, Zhi (Southwest Petroleum University) | Zeng, Fanhua (University of Regina)
Abstract Carbon Capture Utilization and Storage (CCUS) has been widely accepted to be an effective technology to control anthropogenic greenhouse gas emissions globally. For CO2 geo-sequestration, the key is to understand the caprock integrity to assure the safety of the long term sealing effect. However, many caprock integrity studies do not consider the effects of geochemical reactions among CO2, formation brine and caprock. In this work, we used the Lloydminster heavy oil region as the target area and studied the effects of geochemical reactions on the caprock integrity. We collected caprock core samples from both Waseca heavy oil layer and the Deadwood saline aquifer in this area. Then, static tests (Caprock submerged into formation brine over-saturated with CO2 for 40 days) were conducted in the autoclave system under the reservoir pressure (Waseca: 5.4MPa, Deadwood: 11.5MPa) and temperature (Waseca: 25⁰C Deadwood: 35⁰C) to mimic the process of CO2 storage in two candidate formations. Finally, triaxial tests were conducted to compare the change in rock strength between core samples before and after CO2 treatment. Meanwhile, XRD analysis has also been conducted to provide the information of mineral composition change on caprock samples before and after CO2 treatment. Triaxial test results showed that caprock strength has increased (higher axial stress and lateral stress) and fracture pressure increased by 15.84% and 5.45% on average in Waseca and Deadwood formation respectively. Mineralogy analysis indicated that a large amount of carbonate minerals reacted with CO2-saturated brine and stable minerals were generated which help tighten the caprock structure, triggering the self-sealing effect thus caprock strength was enhanced. The research outcomes indicate that in the future site selection for CCS projects, reservoirs with caprocks containing carbonated minerals can be competitive candidates.
- Geology > Mineral (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.71)
Integrated Optimization of Hybrid Steam-Solvent Injection in Post-CHOPS Reservoirs with Consideration of Wormhole Networks and Foamy Oil Flow
Hou, Senhan (University of Regina) | Gu, Daihong (China University of Petroleum Beijing and University of Regina) | Yang, Shikai (University of Regina) | Yang, Daoyong (University of Regina) | Zhao, Min (University of Regina)
Abstract In this paper, integrated techniques have been developed to optimize performance of the hybrid steam-solvent injection processes in a depleted post-CHOPS reservoir with consideration of wormhole networks and foamy oil flow. With the experimentally determined properties of injected gases and reservoir fluids by performing PVT tests, history matching of the reservoir geological model is completed through the relationship between fluid and sand production profiles and reservoir pressure. Meanwhile, the wormhole network has been inversely determined with the newly developed pressure-gradient-based (PGB) sand failure criterion. Once the history matching is completed, the calibrated reservoir geological model is used to optimize the solvent(s) and CO2 concentrations, provided that thermal energy, injection rates, and flowing bottomhole pressures are chosen as the controlling variables. The genetic algorithm has been modified and used to maximize the objective function of net present value (NPV) while delaying the displacement front as well as extending the reservoir life with optimal oil recovery under various strategies. Depending on the formation pressure and temperature, soaking time is optimized as a function of solvent concentration and fluid properties. Subsequently, considering the wormhole network and foamy oil flow, such a modified algorithm can be used to allocate and optimize the production-injection strategies with the NPV as the objective function.
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.73)
- Geology > Geological Subdiscipline (0.68)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Automated feature detection in potash mine gpr data using a cluster ratio derivative (CRD) algorithm (19th International Conference on Ground Penetrating Radar)
Briggs, Tokini (University of Regina) | Okonkwo, Victor (Nutrien Ltd.) | Paranjape, Raman (University of Regina) | van den Berghe, Matthew (Nutrien Ltd.)
GPR systems are utilized during underground potash mining to monitor the condition of the mine roof critical to its safe operation. An auto-picking algorithm has been developed to assist the boring machine operator to make quick, accurate, and consistent safety decisions using GPR data.
- North America > United States > Colorado (0.17)
- North America > Canada > Saskatchewan (0.16)
- Geophysics > Electromagnetic Surveying (0.93)
- Geophysics > Seismic Surveying > Passive Seismic Surveying (0.30)