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Collaborating Authors
Results
Abstract The Wasson Field in the Permian Basin has been the forerunner in the use of carbon dioxide (CO2) enhanced oil recovery (EOR) to tap the potential of the residual oil zone (ROZ). This field is one of the largest ROZ oil producers in the Permian with multi-billion barrels of oil in place, and it is a prime target for EOR as well as CO2 sequestration. Twenty-seven ROZ development projects implemented over three decades in three of the largest Wasson San Andres units (Denver, ODC, and Willard) comprise the scope of data analyzed for this paper. These projects targeted the ROZ pay in mature CO2 floods in the Main Oil Column (MOC) by utilizing existing wells and commingling production from both the MOC and ROZ to reduce costs. However, commingled production makes interpreting the incremental ROZ recovery challenging, which ultimately increases the uncertainty in predicting the technical and economic performance of future ROZ projects. This paper presents a reliable, geo science-driven forecasting technique for ROZ development based on a comprehensive study of the production and injection performance of the 27 ROZ projects. This study uses in-place volumes from a geological model that integrated log, core, and seismic data; historical production and injection data; multi-year zonal flow profiles; and established dimensionless forecasting methods. This paper presents a consistent methodology to: Estimate MOC performance through dimensionless analysis and deduce historical ROZ performance; and, Forecast ROZ ultimate recovery after history matching the resulting injection and production. The estimated ROZ oil recovery across the three Wasson units has been analyzed to establish correlations with the residual oil saturation (Sorw), reservoir quality index (RQI), reservoir heterogeneity, pattern configuration, waterflood maturity, and the water alternating gas (WAG) ratio of the CO2 injection. The key performance indicators of ROZ oil recovery have been determined to be the residual oil saturation and reservoir quality index. The study also shows that the average Sorwin the MOC after waterflooding operations can be higher than the Sorwin the ROZ post"natural" waterflood, resulting in higher oil recovery from the CO2 flood in the MOC than in the ROZ. A correlation has also been established between the ROZ and MOC oil recoveries as a function of floodable volumes using petrophysical properties, which can be applied to analogous ROZ development in mature MOC assets. Most published ROZ oil recovery estimation methods have used reservoir simulation models or analytical approaches like scaling the MOCoil recovery or use of analogous actual ROZ performance. These approaches have limited applicability and cannot be applied widely over different ROZ projects. This paper is the first study that utilizes voluminous historical field data from multiple ROZ projects spread over an extensive duration and acreage across the Wasson Field to estimate ROZ oil recoveries and then propose a novel approach to correlate and scale these estimated ROZ recoveries using petrophysical properties.
- North America > United States > Texas > Gaines County (0.92)
- North America > United States > Texas > Yoakum County (0.83)
- 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)
- (29 more...)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Reduction of residual oil saturation (1.00)
- (2 more...)
Abstract Carbonate reservoirs from Pre-salt layer are responsible for a significant volume of Brazils total oil production. Recovery mechanisms applied are mostly water injection, aiming for pressure maintenance and oil recovery increase through macroscopic oil displacement, complemented by gas injection to dispose produced CO2 rich gas stream into the reservoir. Production strategies were originally built using producers combined with gas and water injectors. Later, based on a serious of technical studies, including the ones described here, most injection wells were converted to water alternating gas (WAG). In the literature, WAG injection is applied mostly to gas injection projects to increase oil recovery and provide mobility control; as a recovery mechanism the WAG process combines the increased microscopic sweep efficiency from the gas with the improved macroscopic sweep efficiency obtained from the water. In this work we perform the screening and evaluation of WAG injection as a recovery mechanism in a heterogeneous carbonate reservoir from the Brazilian pre-salt. For that purpose, we use both analytical and numerical methods, the later using a commercial compositional simulator. The screening indicates that this reservoir is a candidate for WAG injection. Lab data shows thermodynamic miscibility at initial pressure levels and phase behavior observed in experiments is matched to a Peng-Robinson equation of state (EoS). Results from numerical simulation have a good qualitative agreement with analytical results and data from the literature, indicating higher oil recovery for greater gas injection. The increase in oil recovery estimated by numerical simulation is compared with actual data from the literature using dimensionless variables where we observe good agreement of our expectations to previous field results. We conclude that the efficiency of WAG injection, in these reservoirs, relies on factors such as gas availability, miscibility development and flow pattern to be developed due to reservoir heterogeneities (channeling versus dispersive flow).
- North America > United States > Texas (0.93)
- South America > Brazil (0.89)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.35)
- 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)
- (28 more...)
Abstract This study investigates how compositional effects interact with the flow behavior during near miscible (and immiscible) CO2-oil displacements in heterogeneous systems. A series of numerical simulations modeling 1D slim-tube and 2D areal systems were performed using a fully compositional simulator. With negligible numerical dispersion, the fine-scale (Δx=0.005m) slim-tube simulations were performed to provide the "truth case" in terms of the compositional effects and oil/component recovery. A number of grid resolutions were tested to examine cell-size effects on the simulation accuracy. It was found that coarse cell size not only leads to spreading of the displacing front, but also lowers the displacement efficiency by reducing the component stripping effects, as noted by Orr (2007). The corresponding 2D cases are based on a small heterogeneous sector model of dimensions 50m × 10m, in order that the finest scale displacement physics can be modelled accurately. We investigated various flow regimes ranging from viscous fingering to channeling displacements within heterogeneous random correlated fields. CO2 dissolves in oil at near-miscible conditions and improves the mobility of the oil, but leads to earlier breakthrough of CO2 in both fingering and channeling flow. It was also found that the instability of fingering flow could introduce considerable variation in the composition paths during oil displacement by CO2, compared with the slim-tube simulations, particularly in the later stages of the flood. For this reason, heavier component recovery is more likely to be affected and reduced by viscous instability. In the case of channeling flow, compositional effects were less important since the permeability channel dominated the displacement. Both the ultimate oil recovery and component recovery are significantly and about equally reduced, when the underlying heterogeneity is of dominant influence. To summarize, compositional effects can have a very significant impact on the prediction of near-miscible CO2 EOR projects. Issues such as front stability, local displacement efficiency and formation of fingering/channeling during CO2 near-miscible displacement can lead to behavior that is significantly different from immiscible flooding in these systems. The process of mass transfer between CO2 and oil can be hampered to a certain degree by unstable flow depending on the level of heterogeneity. This leads to a further reduction in component recovery, particularly of the heavier components. Lastly, the appropriate upscaling methods considering mass transfer still require further investigation for CO2 near-miscible displacement in field-scale applications. The complete dataset and results of this study are available online as a model case example for testing out potential upscaling techniques for compositional flows in heterogeneous systems (Wang et al. 2019).
- Research Report > New Finding (0.48)
- Overview (0.34)
Screening for EOR and Estimating Potential Incremental Oil Recovery on the Norwegian Continental Shelf
Smalley, P. C. (Imperial College London) | Muggeridge, A. H. (Imperial College London) | Dalland, M.. (Norwegian Petroleum Directorate) | Helvig, O. S. (Norwegian Petroleum Directorate) | Høgnesen, E. J. (Norwegian Petroleum Directorate) | Hetland, M.. (Norwegian Petroleum Directorate) | Østhus, A.. (Norwegian Petroleum Directorate)
Abstract This paper presents an improved approach for rapid screening of candidate fields for EOR and estimation of the associated incremental oil recovery, and the results of applying it systematically to oil fields on the Norwegian Continental Shelf (NCS), an area that already has a high average recovery factor (47%). Identifying, piloting and implementing new improved recovery methods within a reasonable time is important if substantial remaining oil volumes on the NCS are not to be left behind. The approach uses up-to-date screening criteria, and has more sophisticated routines for calculating screening scores and incremental oil recovery compared to previous published methods. The EOR processes screened for are: hydrocarbon miscible and immiscible WAG, CO2 miscible and immiscible WAG, alkaline, polymer, surfactant, surfactant/polymer, low salinity, low salinity/polymer, thermally activated polymers and conventional near well gel treatments. Overall screening scores are derived from sliding-scale scores for individual screening criteria, weighted for importance, and with the ability to define non-zero scores when non-critical criteria are outside their desired range, so avoiding the problem of processes being ruled out completely even though rock or fluid properties are only marginally outside the threshold of applicability. Incremental recoveries are estimated taking into account the existing recovery processes in the field and are capped by theoretical maximum recovery factors derived from theoretical/laboratory values for displacement and sweep. The methodology calculates the expected increment (and uncertainty range) for each EOR process and the increments for the top three compatible process combinations. The methodology was implemented in a spreadsheet-based tool that allowed multiple fields to be screened and the results compared and evaluated. The new tool was used to estimate the potential EOR opportunity for 53 reservoirs from 27 oil fields on the NCS. The results indicate a mid case EOR technical potential of 592 million standard cubic metres (MSm) with a low- to high case range of 320-860 MSm. The most promising processes are low salinity with polymer, surfactant with polymer, and miscible hydrocarbon and CO2 gas injection. Some field clusters were identified that could provide economies of scale for such processes. The EOR screening study has enabled the Norwegian Petroleum Directorate to advocate EOR-technology studies, including pilots, in specific regions or fields. Such pilots will play an important role in verifying process feasibility and narrowing the uncertainty range for incremental recovery potential.
- Asia > Middle East (0.88)
- Europe > Norway (0.67)
- Europe > United Kingdom > North Sea (0.46)
- North America > United States > Alaska > North Slope Borough (0.46)
- North America > United States > Alaska > North Slope Basin > Duck Island Field > Endicott Field > Kekiktuk Formation (0.99)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > Alwyn Area > Block 3/9b > Alwyn Area > Alwyn South Field > Dunbar Field (0.99)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > Alwyn Area > Block 3/8a > Alwyn Area > Alwyn South Field > Dunbar Field (0.99)
- (13 more...)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Miscible methods (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)
Suppressing Frontal Instabilities and Stabilizing Miscible Displacements with Time-Dependent Rates for Improved Oil Recovery
Yuan, Qingwang (University of Regina) | Wang, Shuoshi (University of Oklahoma) | Wang, Jinjie (China University of Geosciences) | Zeng, Fanhua (University of Regina) | Knorr, Kelvin D. (Saskatchewan Research Council) | Imran, Muhammad (Saskatchewan Research Council)
Abstract The frontal instabilities are a key control factor which can significantly affect the sweep efficiency and oil recovery in miscible flooding processes. Under unfavorable viscosity ratio between injection solvent and oil, the frontal instabilities are nearly unavoidable. However, how to suppress the instabilities, especially with low additional costs, should be carefully investigated. The present study examines the time-dependent displacement rates on flow instabilities in miscible flooding. Within the capacity of injection pumps, the injection rates are varied with time in a fast alternating manner. It is found that this kind of variable rates can stabilizing frontal instabilities by enhancing initial uniform mixing of solvent and oil. It therefore suppresses the later development of instabilities. Eventually, a much less unstable front is obtained when compared with the constant injection rate. Other parameters such as the amplitude of rates are also examined. The variations of propagation of front with time are analyzed for the change of rate strength. It is can therefore be concluded that this kind of time-dependent rate can improve oil recovery at very low additional rate within the capacity of pumps for the field EOR processes.
- North America > United States (0.28)
- North America > Canada (0.28)
Abstract Immiscible Water Alternating Gas (IWAG) is an EOR process whereby water and immiscible gas are alternately injected into a reservoir to provide better sweep efficiency and reduce gas channelling from injectors to producer wells, aiming to stabilize the displacement front and increase contact with the unswept areas of the reservoir. In this work, we present a summary of best practices for laboratory evaluation of IWAG. This work was motivated by observations related to the way laboratory measurements are normally done, which could result in erroneous interpretation if the results were to be used directly for the design of a field application. The set of best practices were collected from own work expanding over two decades of laboratory work, discussion with experts from laboratory services and research centres, and a comprehensive literature review. They were tested in a laboratory workflow and compared to conventional workflows used by most laboratories. The recommended approach covers steps from sample preparation, experimental setup, measurement protocols, guideline for process design, and data QA/QC for later use in reservoir simulation. Among the best practices, particular attention is given to the type of fluids and samples used for the measurements based on the strong effect of rock-fluid interactions on the IWAG performance. The layout of the experimental setup, and how the injection and displacement process is done and the flow effects quantified. Other best practices relate to the selection of the WAG slug ratio, and required initial conditions of the core where the laboratory testing is done. The number of cycles in the WAG injection affects the recovery. On the initial condition of the sample, the knowledge of the sample wettability at the start of the WAG is critical since the optimum ratio is influenced by the wetting state of the rock. A WAG ratio of 1:1, which is the most popular in field applications, is not necessarily the most appropriate. Regarding flow properties, relative permeability should be evaluated under three-phase conditions and making sure hysteresis effects are well captured data in general not readily available. Special attention should be given to the selection of correlations for calculating three-phase relative permeability widely reported in the literature; in most cases they are not accurate for WAG injection since they do not consider special treatment of water-gas cycle. We present a side by side comparison of the impact on the laboratory results will be given on using recommended best practices to more routine laboratory implementations. These best practices, with focus on immiscible WAG, provide a new unique workflow for the execution of laboratory programs supporting a better understanding of the involved phenomena and providing accurate data for immiscible WAG process design.
- South America (1.00)
- Asia (1.00)
- Europe > United Kingdom (0.93)
- North America > United States > Texas (0.46)
- Geology > Geological Subdiscipline (0.93)
- Geology > Rock Type (0.68)
- Geology > Mineral > Silicate > Phyllosilicate (0.68)
- South America > Argentina > Patagonia > Neuquén > Neuquen Basin (0.99)
- North America > United States > Texas > Permian Basin > Central Basin > Word Group > San Andres Formation (0.99)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > Block 211/25 > Statfjord Field > Statfjord Group (0.99)
- (6 more...)