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Summary For ultratight shale reservoirs, wettability strongly affects fluid flow behavior. However, wettability can be modified by numerous complex interactions and the ambient environment, such as pH, temperature, or surfactant access. This paper is a third-phase study of the use of surfactant imbibition to increase oil recovery from Bakken shale. The surfactant formulations that we used in this paper are the initial results that are based on our previous study, in which a group of surfactant formulations was examinedโbalancing the temperature, pH, salinity, and divalent-cation content of aqueous fluids to increase oil production from shale with ultralow porosity and permeability in the Middle Member of the Bakken formation in the Williston basin of North Dakota. In our previous study, through the use of spontaneous imbibition, brines and surfactant solutions with different water compositions were examined. With oil from the Bakken formation, significant differences in recoveries were observed, depending on compositions and conditions. Cases were observed in which brine and surfactant (0.05 to 0.2 wt% concentration) imbibition yielded recovery values of 1.55 to 76% original oil in place (OOIP) at high salinity (150 to 300 g/L; 15 to 30 wt%) and temperatures ranging from 23 to 120ยฐC. To advance this work, this paper determines the wettability of different parts of the Bakken formation. One goal of this research is to identify whether the wettability can be altered by means of surfactant formulations. The ultimate objective of this research is to determine the potential of surfactant formulations to imbibe into and displace oil from shale and to examine the viability of a field application. In this paper, through the use of modified Amott-Harvey tests, the wettability was determined for cores and slices from three wells at different portions of the Bakken formation. The tests were performed under reservoir conditions (90 to 120ยฐC, 150- to 300-g/L formation-water salinity), with the use of Bakken crude oil. Both cleaned cores (cleaned by toluene/methanol) and untreated cores (sealed, native state) were investigated. Bakken shale cores were generally oil-wet or intermediate-wet (before introduction of the surfactant formulation). The four surfactant formulations that we tested consistently altered the wetting state of Bakken cores toward water-wet. These surfactants consistently imbibed to displace significantly more oil than brine alone. Four of the surfactant imbibition tests provided enhanced-oil-recovery [(EOR) vs. brine water imbibition alone] values of 6.8 to 10.2% OOIP, incremental over brine imbibition. Ten surfactant imbibition tests provided EOR values of 15.6 to 25.4% OOIP. Thus, imbibition of surfactant formulations appears to have a substantial potential to improve oil recovery from the Bakken formation. Positive results were generally observed with all four surfactants: amphoteric dimethyl amine oxide, nonionic ethoxylated alcohol, anionic internal olefin sulfonate, and anionic linear ฮฑ-olefin sulfonate. From our work to date, no definitive correlation is evident in surfactant effectiveness vs. temperature, core porosity, core source (i.e., Upper Shale or the Middle Member), or core preservation (sealed) or cleaning before use.
- North America > United States > South Dakota (1.00)
- North America > United States > North Dakota (1.00)
- North America > United States > Montana (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)
- (6 more...)
Summary The Dykstra-Parsons method (Dykstra and Parsons 1950) is used to predict the performance of waterflooding in noncommunicating stratified reservoirs. Much interest has been shown recently in the application of the method to chemical flooding, particularly for the case of polymer injection used for mobility control. The original method assumes that the reservoir layers are horizontal; however, most oil reservoirs exhibit a dip angle, with water being injected in the updip direction. Therefore, it is important to account for the effect of inclination on the performance of the method. A modification of the Dykstra-Parsons equations is obtained to account for reservoir inclination. The developed model includes a dimensionless gravity number that accounts for the effect of the dip angle and the density difference between the displacing and displaced fluids. The derived equation that governs the relative locations of the displacement fronts in different layers is nonlinear, includes a logarithmic term, and requires an iterative numerical solution. This solution is used to estimate the fractional oil recovery, the water cut, the injected pore volume, and the injectivity ratio at the time of water breakthrough in successive layers. Solutions for stratified systems with log-normal permeability distribution were obtained and compared with horizontal systems. The effects of the gravity number, the mobility ratio, and the Dykstra-Parsons permeability-variation coefficient (VDP) on the performance were investigated. Cases of updip and downdip injection are discussed. It was found that for a positive gravity number (updip water injection), performance is enhanced in terms of delayed water breakthrough, increased fractional oil recovery, and decreased water cut as compared with horizontal layers. This occurs for both favorable and unfavorable mobility ratios but is more evident in unfavorable mobility ratios and more-heterogeneous cases. For the case of a negative gravity number (downdip water injection or updip gas injection), the opposite behavior was observed. The results were also compared with the performance of inclined communicating reservoirs with complete crossflow. The effect of communication between layers was found to improve fractional oil recovery for favorable and unit mobility ratios and decrease recovery for unfavorable mobility ratio.
- Asia (1.00)
- North America > United States > Texas (0.68)
- 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)
- (21 more...)
Subsurface Uncertainty Assessment for a New Carbonate Field Development
Ouezzani, Mohammed Ridha (Abu Dhabi Marine Operating Co.) | Belery, Paul (Abu Dhabi Marine Operating Co.) | El-Kassawneh, Reyad (ADMA-OPCO) | Daify, Hossam (Abu Dhabi Marine Operating Co.) | Ishiyama, Tomohide (Abu Dhabi Marine Operating Co.) | Yoshida, Koichi (Inpex Corporation) | Zidan, Maher (Abu Dhabi Marine Operating Co.)
Abstract The objective of this paper is to present an integrated approach to quantify subsurface uncertainties and to share the assessments that have been applied in the subsurface studies of a new offshore oil field development in United Arab Emirates. A methodology was developed to review and rank the various subsurface uncertainties. Seismic and geological tools were used to assess uncertainties of static parameters, while integration of all uncertainties was made in the dynamic simulation model. New approaches were implemented to address two important parameters: Critical Water Saturation and Permeability. Critical Water Saturation uncertainty was derived by history matching production test data using a Saturation-Versus-Height model coupled with a Fractional Flow equation. For estimating uncertainty on Permeability, correlations with core derived fracture densities were developed. Uncertainty on the Critical Water Saturation was found to have the highest impact on oil recovery. This uncertainty is related to an observation already made for other carbonate reservoirs where perforated intervals are sometimes producing at very low water-cut in spite of high water saturations interpreted from the logs. This uncertainty review allowed updating the Dynamic Model with more robust P50 estimates of its parameters. The updated model was used to define a new base case development well scheme and production profile. The study was important in maturing the development studies further. It was used in particular not only for updating the Dynamic Model, but also for defining future studies, preparing a data acquisition plan, and identifying mitigation actions to reduce the subsurface risks.
- Reservoir Description and Dynamics > Reservoir Simulation > Evaluation of uncertainties (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- (4 more...)
Abstract Development of tight or low permeability reservoirs (e.g. Bakken formation) commences to reveal its potential and significance and expected to become even more essential in the future. The Canadian Bakken has been produced for over 40 years. At present, the combination of horizontal well drilling and the new multi-stage fracturing and completion technologies has been the key to economically unlocking the vast reserves of the Bakken formation. Parametric studies of fracture geometry on well productivity and oil recovery are essential for a successful hydraulic fracturing stimulation treatment. In this paper, we will investigate the best hydraulic fracturing scenario for Bakken formation and the effects of fracture geometries on oil recovery. More specifically, a geological model is firstly built using typical fluid and rock properties in Bakken formation; the horizontal wells with multistage hydraulic fractures will then be modeled using local grid refinement (LGR) and history matched based on the field production data. Various fracture treatment designs are evaluated, which include the investigation of various fracture spacing, lengths, and fracture locations on the horizontal wells. The results of this study show that, employing multistage hydraulic fracturing along horizontal wells can significantly improve oil recovery in Bakken formation. Compared to fracture length, fracture spaces or fracture numbers have greater impacts on oil recovery. More importantly, for the same fractured volume in the reservoir (i.e., the same usage of proppant and fracturing fluid), fractures with longer and smaller fracture numbers lead to a similar oil recovery compared to shorter but larger fracture numbers along the horizontal well laterals.
- North America > United States > South Dakota (1.00)
- North America > United States > North Dakota (1.00)
- North America > United States > Montana (1.00)
- (2 more...)
- Geology > Geological Subdiscipline (0.50)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.48)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Well Completion > Hydraulic Fracturing > Multistage fracturing (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)
Abstract Modern horizontal well completion technologies consisting of cased or openhole wellbores and multiple hydraulic fractures have revolutionized production from very low permeability oil and gas reservoirs. This paper extends the application of these completions to production systems using thermal Enhanced Oil Recovery (EOR) processes. It reports the results of an extensive simulation study to evaluate the performance of different completion technologies using horizontal wells with and without multiple hydraulic fractures. The results indicate that combination of horizontal wells with multiple fractures increases access to the reservoir and enhances fluid injectivity, improves sweep efficiency and time, accelerates oil production rates and increases ultimate oil recovery. Proposed production system is especially beneficial in reservoirs with high heterogeneity in fluid and rock properties. It lowers the risk of injected fluid channeling through high permeability segments and natural fractures; thereby improving the injection profile and reducing by-passing of the reservoir fluid. In addition, the paper provides completion recommendations for avoiding some of the operational issues that usually come up when considering horizontal wells, and, hydraulic fracturing for EOR systems.
- Europe (1.00)
- Asia (0.93)
- North America > United States > Texas (0.69)
- (2 more...)
- 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)
- (23 more...)
Geomechanics Considerations in Enhanced Oil Recovery
Teklu, Tadesse Weldu (Colorado School of Mines) | Alameri, Waleed (Colorado School of Mines) | Graves, Ramona M. (Colorado School of Mines) | Tutuncu, Azra N. (Colorado School of Mines) | Kazemi, Hossein (Colorado School of Mines) | Alsumaiti, Ali M. (The Petroleum Institute)
Abstract Geomechanics plays significant role in decisions regarding all phases of exploration and production of oil and gas. Specifically, geomechanics influences prospect appraisal, field development, and primary, secondary, and tertiary production activities. Injection of enhanced oil recovery (EOR) fluids such as polymer, steam and gas/CO2 affect reservoir stress redistribution and re-orientation in the field. Hence geomechanics studies need to be conducted in every step of the EOR processes, from EOR screening to abandonment. This paper reviews geomechanical issues related to polymer, steam and hydrocarbon gas/CO2 continuous and water-alternating-gas flooding both in sandstone and carbonate formations. A number of published laboratory and field case studies will be presented and discussed in regard to geomechanics issues. The geomechanical effects pertinent to waterflooding and EOR processes in unconventional reservoirs such as shale reservoirs and oil sands will also be discussed. Finally, reservoir properties affected by stress changes and how to incorporate it in reservoir modeling will be discussed.
- North America > United States > Texas (1.00)
- Europe > Norway (0.68)
- Asia > Middle East > UAE > Abu Dhabi Emirate > Abu Dhabi (0.28)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.89)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.35)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Asia Government > Middle East Government (0.46)
- North America > United States > Wyoming > Powder River Basin > NPR-3 > Teapot Dome Field > Wall Creek Formation (0.99)
- North America > United States > Wyoming > Powder River Basin > NPR-3 > Teapot Dome Field > Tensleep Formation (0.99)
- North America > United States > Wyoming > Powder River Basin > NPR-3 > Teapot Dome Field > Sussex Formation (0.99)
- (12 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- (7 more...)
Abstract This paper describes an easy-to-use and fast-track roadmap for Enhanced Oil Recovery (EOR) Prefeasibility Study including (1) screening of EOR suitable methods 2) estimating of additional recovery with mechanistic 3D models 3) evaluating preliminary economics (NPV) for field scale application 4) assessing the main uncertainties to reservoir, fluids and economical parameters. Oil-production from EOR projects represents currently about 4% of the worldwide production; this ratio is expected to increase significantly in the near future. EOR projects require in general important investments often in matured fields. It is therefore important for a decision maker to have a global view of the main technical and economical expectations and risks ahead of an EOR project decision. This roadmap helps identify ahead of an EOR project the main technical and economic challenges and provides a first Go/No-Go taking into account the main uncertainties and risks associated to this type of project. The main results of this roadmap are a set of pre-defined mechanistic 3D models with different reservoir geometries and suitable for 7 EOR methods (polymer, surfactant, SP flooding, steam injection, SAGD, in situ combustion, gases injection) and a simple but robust economic model providing a set of default technical and economical input values. Risk analysis is performed on these technical and economical results using either a deterministic or a probabilistic approach. The outcome of this roadmap is at field scale, for a given EOR method, an expected additional recovery factor and the corresponding discounted NPV with an uncertainty analysis on the main technical and economical parameters.
- Asia (1.00)
- North America > United States (0.46)
- North America > Canada (0.28)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Thermal methods (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Surfactant Enhanced Oil Recovery from Naturally Fractured Reservoirs
Lu, Jun (The University of Texas at Austin) | Goudarzi, Ali (The University of Texas at Austin) | Chen, Peila (The University of Texas at Austin) | Kim, Do Hoon (The University of Texas at Austin) | Britton, Christopher (The University of Texas at Austin) | Delshad, Mojdeh (The University of Texas at Austin) | Mohanty, Kishore K. (The University of Texas at Austin) | Weerasooriya, Upali P. (The University of Texas at Austin) | Pope, Gary A. (The University of Texas at Austin)
Abstract Large volumes of oil remain in naturally fractured carbonate oil reservoirs and water floods are often very inefficient because many of these reservoirs are mixed-wet or oil-wet as well as extremely heterogeneous. Naturally fractured reservoirs are challenging targets for chemical flooding because they typically have a high permeability contrast between the fractures and the matrix with low to extremely low matrix permeability. In addition, some of the world's largest oil reservoirs are fractured carbonates with high reservoir temperature and high salinity formation brine and some of them also have low API gravity oils, which also increases the difficulty of recovering the oil. We have developed a stable surfactant that shows promising results even when all of these conditions are present at the same time. Both static and dynamic imbibition experiments were done using a fractured carbonate core. These results were interpreted using a mechanistic chemical reservoir simulator.
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.68)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (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)
Abstract Capillary pressure can have a significant effect on multiphase flow in heterogeneous and fractured media, even when there is species transfer between the phases. Modeling the combined non-linearities from phase behavior and capillarity in the multiphase flow equations for heterogeneous and fractured media may be one of the most complicated problems in reservoir simulation. In this work, we present an efficient numerical scheme that uses higher-order methods for the first time to model capillarity in fully compositional three-phase flow. We introduce a simple local computation of the capillarity pressure gradients in the fractional flow formulation in terms of the total flux. Complications arising from gravity and capillarity are resolved in the upwinding with respect to phase fluxes. Our choice of the Mixed Hybrid Finite Element Method for the pressure and flux fields is an accurate and natural approach to compute the capillary pressure gradients and fluxes at the interface between regions of different permeabilities. We present various examples on both core- and large-scales to demonstrate powerful features of our capillary pressure modeling and the upwinding with gravity and capillary pressure. The examples include layered and fractured domains.
ABSTRACT In order to investigate the effects of viscous ratio (water/oil) and the connectivity of flow paths in fracture network on oil recovery from a single fracture, two kinds of water flooding simulations using lattice Boltzmann method have been conducted to single fracture models of different aperture distribution. For the first simulation, the viscous ratio is changed by changing the water viscosity. For the second simulation, the position of inlet and outlet is changed considering the connectivity of flow paths in fracture network. From these simulations, followings are cleared. Oil recovery improves as the viscous ratio becomes higher, because the sweep efficiency improves and the residual oil on the fracture surface decreases. Oil recovery is affected by the aperture distribution around the inlet and outlet. In particular, oil recovery becomes higher when both inflow and outflow of injected water are difficult by small aperture around both inlet and outlet, and it becomes lower when a simple and straight predominant flow path is formed.
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (0.70)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (0.64)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Multiphase flow (0.48)