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Collaborating Authors
Results
Analysis of Vertical Permeability and Its Influence on CO2 Enhanced Oil Recovery and Storage in a Carbonate Reservoir
Ren, Bo (The University of Texas at Austin (Corresponding author)) | Jensen, Jerry L. (The University of Texas at Austin) | Lake, Larry W. (The University of Texas at Austin) | Duncan, Ian J. (The University of Texas at Austin) | Male, Frank (The University of Texas at Austin (now with Shell Oil Company))
Summary The objective of this study is to improve understanding of the geostatistics of vertical (bed-normal) permeability (kz) and its influence on reservoir performance during CO2 enhanced oil recovery (EOR) and storage. kz is scrutinized far less often than horizontal permeability (kx, ky) in most geological and reservoir modeling. However, our work indicates that it is equally important to understand kz characteristics to better evaluate their influence on CO2 EOR and storage performance prediction. We conducted this study on approximately 9,000 whole-core triaxial permeability (kx, ky, kz) measurements from 42 wells in a San Andres carbonate reservoir. We analyzed kz data, including heterogeneity, correlation, and sample sufficiency measures. We analyzed wells with the largest and smallest fractions of points with kz > kmax = max(kx, ky) to explore geological factors that coincided with large kz. We quantified these geological effects through conditional probabilities on potential permeability barriers (e.g., stylolites). Every well had at least some whole cores where kz > kmax. This is a statistically justifiable result; only where Prob(kz > kmax) is statistically different from 1/3 are core samples nonisotropic. In conventional core data interpretation, however, modelers usually assume kz is less than kmax. For the well with the smallest fraction (11%) of cores where kz >kmax, the cumulative distribution functions (CDFs) differ and coincide with the presence of stylolites. We found that kz is approximately twice as variable as kx in many wells. This makes kz more difficult to interpret because it was (and usually is) heavily undersampled. To understand the influence of kz heterogeneity on CO2 flow, we built a series of flow simulation models that captured these geostatistical characteristics of permeability, while considering kz realizations, flow regimes (e.g., buoyant flow), CO2 injection strategies, and reservoir heterogeneity. CO2 flow simulations showed that, for viscous flow, assuming variable kx similar to the reservoir along with a constant kz/kx = 0.1 yields a close (within 0.5%) cumulative oil production to the simulation case with both kx and kz as uncorrelated variables. However, for buoyant flow, oil production differs by 10% [at 2.0 hydrocarbon pore volume (HCPV) of CO2 injected] between the two cases. Such flows could occur for small CO2 injection rates and long injection times, in interwell regions, and/or with vertically permeable conduits. Our geostatistical characterization demonstrates the controls on kz in a carbonate reservoir and how to improve conventional interpretation practices. This study can help CO2 EOR and storage operators refine injection development programs, particularly for reservoirs where buoyant flow exists. More broadly, the findings potentially apply to other similar subsurface buoyancy-driven flow displacements, including hydrogen storage, geothermal production, and aquifer CO2 sequestration.
- North America > United States > Texas (1.00)
- Asia > Middle East (1.00)
- Africa (1.00)
- Europe (0.67)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (1.00)
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.69)
- Geology > Sedimentary Geology > Depositional Environment (0.67)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Exmouth Plateau > WA-1-R > Scarborough Field (0.99)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- (33 more...)
- Well Drilling > Drilling Operations > Coring, fishing (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
It is not often that one’s career coincides with the initiation and maturation of a technology. So it has been with my career and the use of carbon dioxide (CO2) to increase oil recovery, or CO2‑EOR (enhanced oil recovery). I started in the E&P business in the early 1970s, about the same time as CO2‑EOR became feasible (maybe economic). But in no way do I claim credit for this success; it is the result of hundreds of highly competent technologists working in labs, on computers, in the field, and planning, always planning. But I do claim a sense of perspective as the technology has matured over the years and now is about to morph to a similar one, though one with a very different objective—CO2 storage. I am drawing comparisons between carbon capture and sequestration (CCS) and CO2‑EOR that are largely based on analyzing field data, not numerical models nor laboratory‑scale experiments, though both have played important supporting roles. Many of the oilfield technologies are transferable from CO2-EOR to CCS. Technologies such as petrophysics, numerical simulation, and anything relating to injection wells should apply. This fact should make it easier for petroleum engineers to make the transition to CCS. Experience from fluid production provides valuable insight for fluid movement and displacement in the reservoir, but production is not directly transferable to conventional CCS, which does not envision the operation of extraction wells as of this writing. There have been no detectable caprock breaches and few surface leaks in CO2-EOR. This observation has resulted in the need for minimal monitoring requirements. However, monitoring for CCS will be a major part of a project. Ascertaining the amount of CO2 retained in subsurface during CO2‑EOR is difficult using data routinely available to the public. The importance of accurate measurements of rates and pressures at wellhead and surface facilities will be even more important for CCS and over a longer time.
- Asia > Middle East > Saudi Arabia (0.17)
- North America > United States > Texas (0.16)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Asia Government > Middle East Government (0.31)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Health, Safety, Environment & Sustainability > Environment > Climate change (1.00)
Summary The knowledge of the effects of instability and heterogeneity on displacements, primarily enhanced oil recovery, and carbon dioxide storage are well known, although they remain difficult to predict. The usual recourse to modeling these effects is through numerical simulation. Simulation remains the gold standard for prediction; however, its results lack generality, being case-specific. There are also several analytic models for displacements that are usually more informative than simulation results. However, these methods apply to steady-state, incompressible flow. Carbon dioxide injection for storage uses compressible fluids and, in the absence of producers, will not approach steady-state flow (Wu et al. 2017). Consequently, it is unlikely that storage will be in reservoirs of open boundaries (steady-state flow). Flow of compressible fluid necessitates the use of closed or partially sealed boundaries, a factor that is consistent with compressible flow. This work deals with the conditions that cause the onset of incipient viscous fingering or Saffman-Taylor (ST) instability. The actual growth and propagation of fingers, a subject of much recent literature, is not discussed here. The original ST formalism of M >1 for gravity-free flow is highly restrictive: it is for linear flow of nonmixing incompressible fluids in steady-state flow. In this work, we relax the incompressible flow restriction and thereby broaden the ST criterion to media that have sealing and/or partially sealing outer boundaries. We use the nonlinear partial differential equation for linear flow and developed analytic solutions for a tracer flow analog and also for a two-fluid compressible flow. The analysis is restricted to stabilized flow and to constant compressibility fluids, but we are not restricted to small compressibility fluids. There is no transition (mixing) zone between displacing and displaced fluids; the displacement is piston-like. The absence of a transition zone means that the results apply to both miscible and immiscible displacements, absent dispersion, or local capillary pressure. The assumption of a sharp interface is to focus on the combined effect of mobility ratio and compressibility. We use the product of the fluid compressibility and pressure drop (cfΔP) to differentiate the compressibility groups (Dake 1978; Dranchuk and Quon 1967), where ΔP is defined as the pressure drop within the specific fluid region. The results will be based on proposed analytical solutions compared to numerical simulation. The proposed formulation is less restrictive than the original ST formalism of M >1 and allows evaluation of viscous fingering initiation or ST stability criterion in the presence of different boundary conditions (open vs. closed boundaries) with compressible fluids under the stated assumptions, which is the scope of this work. The key contribution here is the effect of external boundaries, which consequently makes necessary the use of compressible fluids. Absent compressibility, the necessary condition for the growth of a viscous finger is simply the mobility ratio, M >1. It is the objective of this work to study how the ST criterion is affected by the presence of sealing and partially sealing outer boundaries with the consequent inclusion of compressible flows as in carbon dioxide storage and enhanced oil recovery by gas injection. The results show that adding compressibility always makes displacements more unstable for stabilized background flow, even for a favorable mobility ratio (M <1) at extremely large compressibility (e.g., cf > 5×10 1/psi). For a sealed external boundary (no production or leakage), displacements will become more stable as a front approaches an external boundary for all mobility ratios (M) investigated.
- Research Report > New Finding (0.48)
- Research Report > Experimental Study (0.34)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- (2 more...)
Modeling Effect of Geochemical Reactions on Real-Reservoir-Fluid Mixture During Carbon Dioxide Enhanced Oil Recovery
Venkatraman, Ashwin (Shell E&P Company) | Dindoruk, Birol (Shell E&P Company) | Elshahawi, Hani (Shell E&P Company) | Lake, Larry W. (University of Texas at Austin) | Johns, Russell T. (Pennsylvania State University)
Summary Carbon dioxide (CO2) injection in oil reservoirs has the dual benefit of enhancing oil recovery from declining reservoirs and sequestering a greenhouse gas to combat climate change. CO2 injected in carbonate reservoirs, such as those found in the Middle East, can react with ions present in the brine and the solid calcite in the carbonate rocks. These geochemical reactions affect the overall mole numbers and, in some extreme cases, even the number of phases at equilibrium, affecting oil-recovery predictions obtained from compositional simulations. Hence, it is important to model the effect of geochemical reactions on a real-reservoir-fluid mixture during CO2 injection. In this study, the Gibbs free-energy function is used to integrate phase-behavior computations and geochemical reactions to find equilibrium composition. The Gibbs free-energy minimization method by use of elemental-balance constraint is used to obtain equilibrium composition arising out of phase and chemical equilibrium. The solid phase is assumed to be calcite, the hydrocarbon phases are characterized by use of the Peng-Robinson (PR) equation of state (EOS) (Robinson et al. 1985), and the aqueous-phase components are described by use of the Pitzer activity-coefficient model (Pitzer 1973). The binary-interaction parameters for the EOS and the activity-coefficient model are obtained by use of experimental data. The effect of the changes in phase behavior of a real-reservoir fluid with 22 components is presented in this paper. We observe that the changes in phase behavior of the resulting reservoir-fluid mixture in the presence of geochemical reactions depend on two factors: the volume ratio (and hence molar ratio) of the aqueous phase to the hydrocarbon phase and the salinity of the brine. These changes represent a maximum effect of geochemical reactions because all reactions are assumed to be at equilibrium. This approach can be adapted to any reservoir brine and hydrocarbon as long as the initial formation-water composition and their Gibbs free energy at standard states are known. The resultant model can be integrated in any reservoir simulator because any algorithm can be used for minimizing the Gibbs free-energy function of the entire system.
- Europe (0.88)
- North America > United States > Texas (0.29)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Mineral > Carbonate Mineral > Calcite (0.45)
- South America > Brazil > Brazil > South Atlantic Ocean > Santos Basin (0.89)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Sun Field (0.89)
- North America > United States > Mississippi > Anna Field (0.89)
- (2 more...)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Fluid modeling, equations of state (1.00)
Ethane-Based Enhanced Oil Recovery: An Innovative and Profitable Enhanced-Oil-Recovery Opportunity for a Low-Price Environment
McGuire, Patrick L. (International Reservoir Technologies) | Okuno, Ryosuke (University of Texas at Austin) | Gould, Thomas L. (International Reservoir Technologies) | Lake, Larry W. (University of Texas at Austin)
Summary This paper summarizes the current state of the ethane industry in the United States (US) and explores the opportunity for using ethane for enhanced oil recovery (EOR). We show both simulation data and field examples to demonstrate that ethane is an excellent EOR injectant. After decades of research and field application, the use of carbon dioxide (CO2) as an EOR injectant has proved to be very successful. However, there are limited supplies of low-cost CO2 available, and there are also significant drawbacks, especially corrosion, involving its use. The rich gases and volatile oils developed by horizontal drilling and fracturing in the shale reservoirs have brought about an enormous increase in ethane production. Ethane prices have dropped substantially. In the US, ethane is no longer priced as a petrochemical feedstock, but is priced as a fuel. Also, substantial quantities of ethane are currently being flared. Ethane-based EOR can supplement the very successful CO2-based EOR industry in the US. There simply is not enough low-cost CO2 available to undertake all the potential gas EOR projects in the US. The current abundance of low-cost ethane presents a significant opportunity to add new gas EOR projects. The ethane-based EOR opportunity can be summarized as follows: CO2-based EOR works well, and is well-understood. Ethane has more solubility in oil, lower minimum miscibility pressures (MMPs), and better solvent efficiency than CO2. Ethane is operationally simpler than CO2 for EOR. Ethane is now inexpensive, and will likely stay inexpensive. Ethane-based EOR has become a viable option in the Lower 48 (lower 48 states in US). Large volumes of low-cost ethane are available. Recent additions to the growing ethane infrastructure now deliver ethane to locations where ethane-based EOR targets are plentiful.
- North America > United States > Texas (1.00)
- North America > United States > Oklahoma (1.00)
- North America > United States > Alaska > North Slope Borough (0.46)
- Geology > Rock Type > Sedimentary Rock (0.48)
- Geology > Petroleum Play Type > Unconventional Play (0.46)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (39 more...)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Gas-injection methods (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- (2 more...)
Modeling Impact of Aqueous Ions on solubility of CO2 and its Implications for Sequestration
Venkatraman, Ashwin (The University of Texas at Austin) | Argüelles-Vivas, F. J. (The University of Texas at Austin) | Okuno, Ryosuke (The University of Texas at Austin) | Singh, Gurpreet (The University of Texas at Austin) | Lake, Larry W. (The University of Texas at Austin) | Wheeler, Mary F. (The University of Texas at Austin)
Abstract CO2 solubility in brine is sensitive to ions as several complexes may result from geochemical reactions. Recent experiments show difference in solubility for brine solutions with equal ionic strength but different salts (NaCl, CaCl2 and KCl). Hence, current methods that incorporate the effect of ions solely by measuring the ionic strength are inadequate to model CO2 solubility in brine. In this research, a new solubility model that accounts for the presence of particular ions has been developed using the Gibbs free energy minimization model. The Gibbs free energy function provides the advantage of combining different thermodynamic models - Equation of State (EOS) for hydrocarbon or gas phase components and activity coefficient model for aqueous phase components. The developed model uses Pitzer activity coefficients for aqueous phase components where experimental data available for individual salt mixtures have been used to tune coefficients. We use this solubility model to quantify the impact of particular ions for CO2 sequestration application. We discuss strategies for modifying the brine composition that can increase CO2 solubility and hence, aid CO2 sequestration.
- Research Report > New Finding (0.34)
- Research Report > Experimental Study (0.34)
Abstract This paper summarizes the current state of the ethane industry in the United States and explores the opportunity for using ethane for enhanced oil recovery. We show both simulation data and field examples to demonstrate that ethane is an excellent EOR injectant. After decades of research and field application, the use of CO2 as an EOR injectant has proven to be very successful. However, there are limited supplies of low cost CO2 available, and there are also significant drawbacks, especially corrosion, involving its use. The rich gasses and volatile oils developed by horizontal drilling and fracturing in the shale reservoirs have brought about an enormous increase in ethane production. Ethane prices have dropped substantially. In the U.S., ethane is no longer priced as a petrochemical feedstock, but is priced as fuel. Also, substantial quantities of ethane are currently being flared. Ethane-based EOR can supplement the very successful CO2-based EOR industry in the U.S. There simply isn't enough low-cost CO2 available to undertake all of the potential gas EOR projects in the U.S. The current abundance of low-cost ethane presents a significant opportunity to add new gas EOR projects. The ethane-based EOR opportunity can be summarized as follows; CO2-based EOR works well, and is well understood. Ethane is better than CO2 for EOR. Ethane is simpler than CO2 for EOR. Ethane is now inexpensive, and will likely stay inexpensive. Ethane-based EOR has become a viable option in the Lower 48. Large volumes of low-cost ethane are available. Recent additions to the growing ethane infrastructure now deliver ethane to locations where ethane-based EOR targets are plentiful.
- North America > United States > Texas (1.00)
- North America > United States > Oklahoma (1.00)
- North America > United States > Alaska > North Slope Borough (0.68)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Texas > East Texas Salt Basin > East Texas Field > Woodbine Formation (0.99)
- North America > United States > Oklahoma > Northeast Oklahoma Platform Basin > Glenn Pool Field > Glenn Formation (0.99)
- North America > United States > Oklahoma > Northeast Oklahoma Platform Basin > Glenn Pool Field > Bartlesville Formation (0.99)
- (42 more...)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Gas-injection methods (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- (2 more...)
Abstract The capillary pressure heterogeneity or local capillary trapping (LCT) determines the final distribution of CO2 in a saline aquifer during geological carbon sequestration. This locally trapped CO2 would not escape from the storage formation even if caprock integrity is compromised. It is, therefore, essential to predict the extent and storage capacity of LCT during the design of GCS projects. This work employs a fast method based on the geologic criteria to estimate the structures of local capillary traps. The method assumes a critical capillary entry pressure (CCEP) and a geostatistical realization of the reservoir entry pressure field as inputs. It then finds the capillary barriers inside the domain and identifies the grid blocks beneath clusters of barriers. These grid blocks are the local capillary traps. The criterion for choosing the CCEP is important, and we suggest a criterion in this work. We verify this algorithm by full-physics simulations in small 2D and 3D domains. We employ a large CO2 injection rate (Ngr~0.1) to fully sweep the storage domain, followed by a long period of buoyant flow to allow for complete charging of those local capillary traps. We test several CCEPs to determine the most physically representative value by comparing the LCT predicted from both methods. We find that a single value of CCEP enables the geologic algorithm to give a very good approximation of LCT distribution as well as LCT volume in uncorrelated and weakly correlated porous media. This means that the concept of CCEP is a reasonable approximation to the physical process by which traps are filled. LCT can be described in terms of percolation theory. The percolation threshold arises from the competition between connected clusters of barriers and connected clusters of local traps. We show that both the percolated CCEP (corresponding to the percolation of LCT) and optimal CCEP (corresponding to the best match between geologic criteria and full-physics simulation) change with each other in a predictable linear way for the uncorrelated capillary entry pressure field.
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.68)
Abstract When CO2 migrates upwards under buoyancy in the subsurface saline aquifer and encounters local capillary barriers (regions of rock with large capillary entry pressure), CO2 would accumulate beneath these small barriers, and these accumulations are called local capillary trapping (LCT). LCT benefits storage because locally trapped CO2 has a much larger saturation than residual gas, and such trapped gases cannot escape from the formation even if leakage conduits (fractures or fault) in the seal develop during the long-term storage of CO2. Thus predicting and maximizing LCT is valuable in design and risk assessment of geologic storage projects. Modeling LCT is computationally expensive and may even be intractable by using a conventional reservoir simulator. In this work, we decouple the problem into two parts: permeability-based flow simulation and capillary entry pressure-based local capillary trapping phenomenon. The connectivity analysis originally developed for characterizing well-to-reservoir connectivity is adapted to the flow simulation by means of a newly defined edge weight property between neighboring grid blocks, which accounts for the multiphase flow properties, injection rate, and buoyancy effect. Then the connectivity was estimated from shortest path algorithm to predict the CO2 migration behavior and plume shape during injection. A geologic criteria algorithm is developed to estimate the potential LCT only from the entry capillary pressure field. The latter is correlated to a geostatistical realization of permeability field. The extended connectivity analysis shows a good match of CO2 plume computed by the full-physics simulation. We then incorporate it into the geologic algorithm to quantify the amount of LCT structures identified within the entry capillary pressure field that can be filled during CO2 injection. Several simulations were conducted in the reservoirs with different level of heterogeneity (measured by the Dykstra-Parsons coefficient) under various injection scenarios. We demonstrate the reservoir heterogeneity affects the optimal injection rate in maximizing the LCT during injection. Both the geologic algorithm and connectivity analysis are very fast; therefore, the integrated methodology can be used as a quick tool to estimate LCT. It can also be used as a potential complement to the full-physics simulation to evaluate the total safe storage capacity.
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.46)
Abstract A partnership between oilfield operators and the federal government in the coupled CO2 enhanced oil recovery (EOR) and storage projects may bring long-term benefits for both. This paper quantifies the win-win condition for this partnership in terms of an optimum storage tax credit. We introduce a basic conceptual model for the CO2 market and investigate the market sustainability conditions. We quantitatively show how the storage tax credit affects the optimum economic storage capacity of an oilfield as well as the benefits for the oilfield operator and the government. Two field-scale models for the EOR-storage operation are developed, namely Sandstone and Carbonate. The Sandstone model is tuned according to the top 10% performing West Texas CO2-EOR reservoirs while the Carbonate model is tuned according to the moderately performing reservoirs. The EOR-storage performance of the simulated Sandstone and Carbonate reservoirs is likely to be moderate to optimistic where the oil production performance is between 50 and 100 stbd/well and the CO2 utilization is between 5 and 10 Mscf/stb. Assuming $60/stb oil price and $80/tonne anthropogenic CO2 cost, the storage tax credit should be between 20 and $40/tonne to allow for an economically feasible EOR-storage operation and satisfy market sustainability (win-win) for both the oilfield operators and the federal government. Below this range, EOR-storage is infeasible and neither the operators nor the government gain benefits (lose-lose); above the optimum tax credit range the government spends too much while the operator gains benefits (lose-win). This study, however, does not consider the intangible social, economical, and environmental benefits of anthropogenic CO2 storage.
- Government > Tax (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Health, Safety, Environment & Sustainability > Sustainability/Social Responsibility > Sustainable development (1.00)
- (2 more...)