Najafabadi, Nariman Fathi (The University of Texas at Austin) | Delshad, Mojdeh (The University of Texas at Austin) | Sepehrnoori, Kamy (The University of Texas at Austin) | Nguyen, Quoc Phuc (The University of Texas at Austin) | Zhang, Jieyuan
Waterfloods performed in carbonate and naturally fractured reservoirs frequently suffer from relatively poor sweep efficiency by virtue of geological heterogeneity and preferentially oil-wet rock surface commonly seen in these reservoirs. The application of chemical-based wettability modification in such problematic formations has become one of the most potential enhanced oil recovery techniques for the worldwide abundance of fractured carbonates with significant amount of remaining oil.
Chemical stimulation with surfactant or electrolyte to alter the wettability towards more water-wetness has the potential to enhance water imbibition to expel more oil from matrix to the fractures. The countercurrent interaction at matrix-fracture interface involves interplay of capillary, gravitational and viscous forces. A clear understanding of these processes is required for an optimum oil recovery design and field implementation in fractured carbonate reservoirs. To this end, we have developed a systematic experimental and modeling approach on the combined benefit of wettability alteration for enhanced water imbibition and interfacial tension reduction.
Both natural and forced imbibition experiments were performed in mixed-wet rocks where oil volume produced was recorded for sequential injection of water, alkali, and surfactant/alkali mixture. The alkali was effective in wettability modification and enhanced water imbibition. Additional oil was recovered by injection of surfactant/alkali mixture following alkali injection due to interfacial tension reduction and oil mobilization. A wettability alteration model based on these mechanisms was developed and implemented in a compositional chemical flooding simulator. The experiments were successfully modeled with the enhanced simulator.
A better understanding of mechanisms involved in improved recovery of oil from fractured carbonates using wettability modifier will aid in identifying and implementing future field demonstration projects.
We present a sharp-interface mathematical model of CO2 migration in saline aquifers, which accounts for gravity override and capillary trapping. The major differences with respect to previous investigations is that we model the shape of the plume during the injection period, we account for regional groundwater flow during the post-injection period, and we introduce rigorously the reduction in water mobility due to trapping of the CO2.
The model leads to a nonlinear advection-diffusion equation, in which the diffusive term is due to buoyancy forces, not physical diffusion. The three key dimensionless groups are the mobility ratio between the injected and initial fluids (M), the gravity number (Ng), and a newly defined trapping coefficient (G). For the case of interest in geological CO2 storage, in which the mobility ratio is much smaller than 1, the solution is largely insensitive to the value of the gravity number. Under these conditions, the mathematical model can be simplified to a hyperbolic model.
We present a complete analytical solution to the hyperbolic model that includes the injection, early post-injection, and late post-injection periods. Despite the fact that the solution involves the interaction of a sharp imbibition front with a drainage rarefaction front, it admits a closed-form expression. The main outcome of the analytical developments presented here is a formula that predicts the ultimate footprint on the CO2 plume, and the time scale required for complete trapping. Both a formula that predicts the ultimate footprint on the CO2 plume, and the time scale required for complete trapping. Both quantities depend strongly on the shape of the plume at the end of the injection period, which must - therefore - be modeled.
A second application of the analytical solution is a formulation for upscaling the capillary trapping coefficient from the laboratory scale to the basin scale. Explicit expressions are given for the megascopic and gridblock-effective trapping coefficients, as functions of the local trapping coefficient, the mobility ratio, and the grid resolution. Although the expressions derived are based on a one-dimensional sharp-interface model, we anticipate that they will have broader applicability to injection scenarios with unfavorable mobility ratio and dominated by gravity override.
Enhanced-Oil Recovery (EOR) for asset acquisition or rejuvenation involves intertwined decisions. In this sense, EOR operations are tied to a perception of high investments that demand EOR workflows with screening procedures, simulation and detailed economic evaluations. Procedures have been developed over the years to execute EOR evaluation workflows.
We propose strategies for EOR evaluation workflows that account for different levels of available information. These procedures have been successfully applied to oil property evaluations and EOR applicability in a variety of oil reservoirs. The methodology relies on conventional and unconventional screening methods, emphasizing identification of analogues to support decision making. The screening phase is combined with analytical or simplified numerical simulations to estimate full-field performance while maintaining rational reservoir segmentation procedures.
This paper fully describes the EOR decision-making procedures using field case examples from Asia, Canada, Mexico, South America and the United States. The type of assets evaluated includes a spectrum of reservoir types, from oil sands to light oil reservoirs. Different stages of development and information availability are discussed. Results show the advantage of flexible decision-making frameworks that adapt to the volume and quality of information by formulating the correct decision problem and concentrate on projects and/or properties with apparent economic merit.
Our EOR decision-making approaches integrate several evaluation tools, publicly or commercially available, whose combination depends on availability and quality of data. The decision is laid out using decision-analysis tools coupled with economic models and numerical simulation. This allows integrated teams to collaborate in the decision making process without over-analyzing the available data. One interesting aspect is the combination of geologic and engineering data, minimizing experts' bias and combining technical and financial figures of merit rationally. The proposed methodology has proved useful to screen and evaluate projects/properties very rapidly, identifying whether or not upside potential exists.
Horizontal and multi-lateral wells have become increasingly important and represent a growing percentage of production wells. They are used to maximize the well to reservoir contact and improve oil recovery in a cost efficient manner. This is especially true for offshore fields where these wells are used to drain large areas with limited platform capacities. Commonly, a horizontal well trajectory undergoes undulations that may result in special wellbore flow dynamics. In addition, technologies such as intelligent completions can be used to regulate flow from various perforation intervals or producing laterals.
Our recent field studies required the simulation of special wellbore dynamic behavior specific to horizontal/multi-lateral wells. It is a significant challenge to capture such behavior in a simulation model. This paper covers the following issues of horizontal/multi-lateral well simulation.
The simulation of these issues requires special techniques, such as the use of a discritized well model. A discritized well is represented by multiple segments along the path of the wellbore. This option provides flexibility in the control of appropriate parameters by segment to properly simulate the different issues that arise with horizontal/multi-lateral wells. In addition, local grid refinement is often needed to accurately capture the well trajectory and detailed fluid flow and pressure profiles.
This paper discusses the previously mentioned horizontal/multi-lateral well fluid and completion dynamics and the approach used to simulate them. Simulation results for successful actual field studies as well as semi-synthetic examples are presented.
Kristensen, Morten Rode (Tech. U. of Denmark) | Gerritsen, Margot Geertrui (Stanford University) | Thomsen, Per G. (Technical University of Denmark) | Michelsen, Michael L. (Tech. U. of Denmark) | Stenby, Erling Halfdan (Tech. U. of Denmark)
To facilitate the study of reactive-compositional porous media processes we develop a virtual kinetic cell (single-cell model) as well as a virtual combustion tube (one-dimensional model). Both models are fully compositional based on an equation of state. In this work, we apply the models to analyze phase behavior sensitivity for in-situ combustion, a thermal oil recovery process. For the one-dimensional model we first conduct sensitivity analyses to numerical discretization errors and provide grid density guidelines for proper resolution of in-situ combustion behavior. A critical condition for success of in-situ combustion processes is the formation and sustained propagation of a high-temperature combustion front. Using the models developed we study the impact of phase behavior on ignition/extinction dynamics as a function of the operating conditions. We show that when operating close to ignition/extinction branches, a change of phase behavior model is likely to shift the system from a state of ignition to a state of extinction or vice versa. For both the rigorous equation of state based and a simplified, but commonly used, K-value based phase behavior description we identify areas of operating conditions which lead to ignition. For a particular oil we show that the simplified approach overestimates the required air injection rate for sustained front propagation by 17% compared to the equation of state based approach.
Grieve oil field, discovered in 1954, is located in southeastern Wind River Basin, central Wyoming. This Lower Cretaceous, valley-fill and channelized, Muddy sandstone reservoir is a stratigraphic/structural trap with an average structural dip of 15degrees. Multiple recovery mechanisms have contributed to produce more than 30 million barrels of premium light sweet crude, including gas expansion, down-dip water drive, and re-injection of produced gas into the field's gas cap. The reservoir depth, at 6,900 ft, and oil gravity, 37oAPI, are considered favorable for miscible gravity stable CO2 flooding to enhance oil recovery.
Three distinct reservoir lithofacies are identified within the Muddy channel sand at Grieve Field, which are overlain by a low-permeability sandstone interval of bay-head delta deposition. Wettability tests indicate that the reservoir rock is weakly water-wet. A full-field simulation model was developed to simulate the production history and forecast the performance of various CO2 flooding scenarios.
The simulation evaluation concluded that gravity stable CO2 flooding can be an effective EOR method for the Grieve Muddy reservoir. Up to 23 MMSTBO could ultimately be recovered by gravity stable CO2 flooding. To repressurize the reservoir to an operation pressure above the minimum miscibility pressure, a cumulative injection of 90 BSCF or more of CO2 would be needed before any production. Total CO2 purchased is estimated to be in the 119 to 188 BSCF range depending on the operation duration and CO2 injection rate. The net CO2 usage efficiency, the ratio between total purchased CO2 and total produced oil, varies from 7.3 to 8.1 MSCF/BO in the simulated cases. The reservoir has potential to sequester more than 145 BSCF of CO2 at the end of CO2 flooding operation.
Heterogeneity measures have a long history in the oil and gas industry but have fallen somewhat out of favor in recent years with the advent of more statistically robust characterization tools. Theoretically-based correlations between heterogeneity measures and recoveries at various stages of a waterflood appear to be one of the primary tools in the design and early evaluation of floods when they were initially proposed. Field-wide reports of the heterogeneity measures and their relationship to enhanced recovery response were also reported in the literature, but it is unclear as to whether general correlations were developed or widely used as they were for waterflooding.
In this work we evaluate several heterogeneity measures in terms of recovery efficiency and utilization rate in a mature CO2 flood. Core studies available from 41% of the wells in the Little Creek Field, Mississippi were used to compute various heterogeneity measures and the resulting values were correlated with pattern-by-pattern and development area recoveries and CO2 utilization rates at various times over the life of the flood. Weak correlation trends were found for most of the measures when recoveries were evaluated. Slightly stronger correlations were found with utilization rates.
Much more significantly, mapping of the well-by-well heterogeneity measures appear to show geological trends better than traditional maps of the basic parameters that make up the measures. These geological trends were then successfully used to adjust rock-types and guide geostatistical modeling of permeability and porosity when performing reservoir modeling and history matching.
Wu, Xiaolin (Exploration/Devel. Rsch. Inst.) | Zhang, Guoyin (Daqing Research Institute) | Wang, Haifeng (Daqing Research Institute) | Yang, Yong (Daqing Research Institute) | Shan, Cunlong (Daqing Research Institute)
Alkyl benzene surfactants with narrow equivalent weight distribution (NEWD) and desirable structure were prepared by the alkylation of olefin, sulfonation and neutralization. Due to the favorable composition and molecular structure, they prove to have exceptionally high activity and oil displacement ability. The laboratory evaluation indicates: (1) ASP formulation can reduce oil-water interfacial tension (IFT) to/below 10-3 mN/m at very low surfactant concentration (0.05-0.3 wt%) and wide concentration range of alkaline (Na2CO3, 0.8-1.4 wt%). (2) The addition of Na2CO3 instead of NaOH reduces the risk of equipment corrosion and severity of produced fluid treatment. (3) Compared with conventional surfactants, this class of surfactant is much more compatible with Daqing crude oils with different properties. (4) The effect of surfactant chromatographic fractionation on ASP performance is dramatically reduced due to its narrow equivalent weight distribution. (5) Laboratory core flooding can achieved about 20 per cent original oil in place (OOIP) incremental over that for water displacement.
A 75 meter well-spacing ASP flooding field test composed of 3 injectors and 4 producers was conducted in Daqing Sabei area in October, 2004 and was completed in 2005. Effective response began to be observed for the central producing well No. 122 at the injection of 0.09 PV. Water cut decreased by 25.1 percent from 95.3 to 70.2 percent at the injection of 0.378 PV and the period of water cut below 80 percent was maintained for 0.42 PV. The daily oil production increased from 1 to 4 tons. For another producing well No. 133, water cut decreased by 71.3 percent from 99.0 to 28.7 percent at the injection of 0.575 PV. The final oil recovery amounted to 24.66 percent OOIP over water flooding.
Gonzalez, Reinaldo Jose (Advanced Resources International, Inc.) | Eslinger, Eric (Eric Geoscience Inc) | Reeves, Scott R. (Advanced Resources International, Inc.) | Schepers, Karine Chrystel (Advanced Resources International, Inc.) | Back, Thomas (NuTech Solutions)
An integrated methodology combining clustering analysis techniques, geostatistical methods and evolutionary strategy technologies was developed and applied to an area in the SACROC Unit (Permian basin). Clustering methods were applied to well logs and core data with high vertical resolution for many wells to predict porosity, permeability and rock type. Geostatistics was applied to extend the characterization into the inter-well area. Evolutionary strategies were used to refine the characterization to match historical production performance.
The complete approach was tested on an area within the SACROC Unit, acknowledged as a highly heterogeneous carbonate reservoir with complex production history. Three cored wells provided porosity and permeability measurements on a foot-by-foot basis. These measurements coupled with well logs were used to predict porosity, permeability and flow units. Twenty two wells in the study area having foot-by-foot profiles of porosity and permeability were considered sufficient to characterize porosity and permeability in three dimensions. Geostatistical methods were then used to build porosity and permeability models.
As a validation of the characterization procedure, evolutionary strategy jointly coupled with a black oil reservoir model was used to history match production performance of a 0.5 mi2 area. The 65,340 grid-block model had over 50 years of production. Thirteen (13) input parameters were varied during the history match. Among them, a multiplying factor was applied to the permeability realization to account for upscaling effects, varying permeability values without modifying geological heterogeneities identified during the characterization process. No adjustment to porosity characterization was permitted.
A very good history match of individual production was achieved for the center wells of the area, and a good match was also obtained for outer wells production and reservoir pressure where boundary effects existed. This validates the new integrated clustering/geostatistical/evolutionary-strategy approach in this highly heterogeneous carbonate reservoir.
Alkaline/surfactant/polymer (ASP) flooding is of increasing interest and importance due to high oil prices and the need to increase oil production. The benefits of combining alkali with surfactant are well established. The alkali has very important benefits such as lowering interfacial tension and reducing adsorption of anionic surfactants that decrease costs and make ASP a very attractive enhanced oil recovery method provided the consumption is not too large and the alkali can be propagated at the same rate as the synthetic surfactant and polymer. However, the process is complex so it is important that new candidates for ASP be selected taking into account the numerous chemical reactions that occur in the reservoir. The reaction of acid and alkali to generate soap and its subsequent effect on phase behavior is the most crucial for crude oils containing naphtenic acids. Mechanistic simulation of the ASP flood considering the chemical reactions, alkali consumption, and soap generation and the effect on the phase behavior is the key to success of future field operations. Using numerical models, the process can be designed and optimized to ensure the proper propagation of alkali and effective soap and surfactant concentrations to promote low interfacial tension and a favorable salinity gradient. In this paper, we describe the ASP module of UTCHEM simulator with particular attention to phase behavior and the effect of soap on optimum salinity and solubilization ratio. Phase behavior data are presented for sodium carbonate and a blend of surfactants with an acidic crude oil that followed the conventional Winsor phase transition with significant three-phase regions even at low surfactant concentrations. The solubilization data at different oil concentrations were successfully modeled using Hand's rule. Optimum salinity and solubilization ratio were correlated with soap mole fractions using mixing rules. ASP coreflood results were successfully modeled taking into account the aqueous reactions, alkali/rock interactions, and phase behavior of soap and surfactant. Mechanistic simulations give insights into the propagation of alkali, soap, and surfactant in the core and aid in future coreflood and field scale ASP designs.