Summary Laboratory surfactant and hot-water floods have shown a great potential in increasing oil recovery for reservoirs that are naturally fractured and have low-permeability, mixed-wet matrix rocks. Fractured, mixed-wet formations usually have poor waterflood performance because the injected water tends to flow in the fractures and imbibition into the matrix is not very significant. Surfactants have been used to change the wettability for increasing the oil recovery by increased imbibition of the water into the rock matrix. The mechanisms for oil recovery are combined effects of reduced interfacial tension (IFT), reduced mobility ratio, and wettability alteration. The goal of this research is to adapt an existing numerical reservoir simulator to model chemical processes leading to wettability alteration in naturally fractured reservoirs. Surfactants have been used to change the wettability, with the goal of increasing the oil recovery by increased imbibition of the water into the rock matrix. Reservoir simulation is required to scale up the process from laboratory to field conditions, as well as to understand and interpret reservoir data. A chemical-flooding simulator is adapted to model improved-oil-recovery processes involving wettability alteration using surfactants. Multiple relative permeability and capillary pressure curves corresponding to different wetting states are used to model the wettability alteration. Simulations are performed to better understand and predict enhanced oil recovery as a function of wettability alteration, and to investigate the impact of uncertainties in the fracture and matrix properties, reservoir heterogeneity, matrix diffusion, buoyancy-driven flow, initial water saturation, and formation wettability. The proposed wettability-alteration model and its implementation were successfully validated against laboratory experiments. Upscaled simulations indicated the importance of matrix properties on the rate of imbibition. The oil recovery increases with an increase in matrix permeability and a decrease in matrix initial water saturation.

Many pilot tests and several commercial field projects have been performed over the past few decades and have shown that surfactant/polymer and alkaline/surfactant/polymer floods can recovery high percentages of residual oil saturation. However, these chemical processes are sensitive to parameters such as chemical slug size and concentrations, salinity, reservoir heterogeniety and surfactant adsorption among other key parameters. In this study, a sensitivity analysis of these key parameters was performed to optimize a chemical flood design for a mixed-wet dolomite reservoir in the Permian Basin. The simulations were performed using the reservoir simulator UTCHEM, a multiphase, multicomponent chemical flooding simulator. The base case design was developed using a reservoir model provided by the operator, injection and production rate constraints from actual field conditions, brine and oil properties from the field, and chemical properties provided by the EOR laboratory at the University of Texas. An optimum design was selected based on net present value calculated from discounted cash flow analysis. The results of this study showed that chemical flooding this mixed-wet dolomite reservoir is likely to be profitable over at range of crude oil prices based upon the laboratory performance of the surfactant/polymer flood and the optimum process design determined in this study. Introduction A very large amount of remaining oil in the U.S. resides in carbonate reservoirs. Many of these carbonate reservoirs have very low primary and waterflood recovery efficiencies, so much residual and bypassed oil remains as a target for enhanced oil recovery. Enhanced oil recovery methods known as surfactant-polymer (SP) flooding[1–7] and alkaline-surfactant-polymer (ASP) flooding[8–14] have been shown to be effective in recovering remaining oil in many successful pilot tests and some relatively small commercial field projects. Most SP and ASP floods have been done in sandstone reservoirs. However, an SP pilot done in a carbonate reservoir showed promising results.[15] Many past SP and ASP simulation studies have been performed to understand the sensitivity and complexity of chemical flooding.[9,14,17–20] These simulation studies have shown chemical flooding to be sensitive to several design and chemical parameters such as slug sizes, chemical concentrations, and chemical retention due to adsorption and other mechanisms. Wu[18] and Wu et al.[20] did an optimization study of a SP flood for a typical onshore water-wet sandstone reservoir focusing on the optimum design when crude oil was about $20 per Bbl. Wu's optimum SP design consisted of a large slug of low concentration surfactant and polymer followed by little if any polymer and water drives. This design was based upon the assumption the surfactant was active at very low concentrations and had very low adsorption and low crude oil prices. The success of a SP flood depends upon the ability to propagate the surfactant and polymer, overcome chemical adsorption, and improve the sweep efficiency. In this work, an optimization study was performed to meet these three goals and maximize the oil recovery and profitability of a SP flood in a mixed-wet dolomite reservoir. The optimization study included a sensitivity analysis, which included the aforementioned parameters, and an uncertainty analysis, which was extended to other parameters such as kv/kh, capillary desaturation curves (CDC), and permeability. The optimization and sensitivity simulations reported in this paper were performed using UTCHEM, a chemical flooding simulator developed and validated for chemical processes such as SP and ASP. The results of the simulations were analyzed using discounted cash flow to determine the economic feasibility of the optimized SP flood design for a particular carbonate reservoir in the Permian basin.

Laboratory surfactant and hot water floods have shown a great potential in increasing oil recovery for reservoirs that are naturally fractured and have low permeability mixed-wet matrix rocks. Fractured, mixed-wet formations usually have poor waterflood performance because the injected water tends to flow in the fractures and spontaneous imbibition into the matrix is not very significant. Surfactants have been used to change the wettability for increasing the oil recovery by increased imbibition of the water into the matrix rock. The mechanisms for oil recovery are combined effects of reduced interfacial tension, reduced mobility ratio, and wettability alteration. The goal of this research is to adapt an existing numerical reservoir simulator to model chemical processes that lead to wettability alteration in naturally fractured reservoirs. Surfactants have been used to change the wettability with the goal of increasing the oil recovery by increased imbibition of the water into the matrix rocks. Reservoir simulation is required to scale up the process from laboratory to field conditions and to understand and interpret reservoir data. We have adapted the chemical flooding simulator, UTCHEM, to model improved oil recovery processes that involve wettability alteration using surfactants. Multiple relative permeability and capillary pressure curves corresponding to different wetting states are used to model the wettability alteration. Simulations were performed to better understand and predict enhanced oil recovery as a function of wettability alteration and to investigate the impact of uncertainties in the fracture and matrix properties, reservoir heterogeneity, matrix diffusion, buoyancy driven flow, initial water saturation, and formation wettability. Introduction About one-half of the world's oil reservoirs are carbonates and many of them are naturally fractured and mixed wet or oil wet. Typically, more than two-thirds of the original oil in place in these reservoirs remains even after many decades of primary and secondary oil recovery. The fraction of the oil recovered from naturally fractured carbonate reservoirs is typically even less than two-thirds, often much less. Waterflooding produces oil from these reservoirs through spontaneous imbibition of water from the fractures into the rock matrix and the flow of the oil out of the matrix and through the fractures to the production wells. The capillary driving force is strong and effective when the rock is water wet. Unfortunately, many naturally fractured reservoirs are mixed wet or oil-wet with low matrix rock permeability, so the driving force is weak or non existent and the oil recovery is very low. The oil recovery can be improved in such cases by using chemicals[1–8] or heat[9–15] to:decrease the interfacial tension between the oil and water,change the matrix wettability from mixed or oil wet to water wet, andincrease the viscous forces. Babadagli[7] compared the rate of capillary imbibition for both light and heavy crude oils by chemical (surfactant and polymer) and hot water in corefloods. The results showed the rate of oil recovery by water imbibition was the highest for the hot water injection. However, surfactant addition yielded greater oil recovery at a faster production rate than the brine case. Babadagli also conducted experiments to investigate the use of surfactants and hot water on heavy oil production from fractured chalk. The results indicated a higher recovery when the combination of hot water and surfactant was used for heavy oils. Austad et al.[2] conducted imbibition experiments in nearly oil-wet, low-permeable (1 to 2 md) rocks with and without surfactant present. A 1 wt% cationic dodecyltrimethyl-ammonium bromide surfactant solution was used. Their results indicated a sudden increase in oil recovery when surfactant was present. Laboratory experiments using Yates San Andreas reservoir core indicated that the injection of dilute nonionic surfactants resulted in an improved oil recovery compared to injection of brine.[5]

No abstract

No abstract