Energy Policy Act of 2005 (Ultra-deepwater and Unconventional Resources Program)
Field Demonstration of Alkaline Surfactant Polymer Floods in Mature Oil Reservoirs Brookshire Dome, Texas
The primary objective of this project is to improve oil recovery in mature onshore oilfields by demonstrating the potential for ASP (alkaline/surfactant/polymer) flooding through a systematically planned pilot flood based on extensive laboratory phase behavior and core flood studies.
Layline Petroleum 1, LLC, Houston, TX 77024
TIORCO LLC, Denver, CO 80231
The University of Texas at Austin, Austin, TX 78712
The largest onshore oil reserves in the United States are to be found in the mature oilfields that have been produced by primary and secondary recovery methods but still contain over 65% of their original oil in place. This resource represents 377 billion barrels of oil that is not recoverable by traditional methods. This project aims to demonstrate that the use of ASP flooding in appropriately selected reservoirs can result in incremental oil production of 10 to 20 percent of the original oil (15 to 30 percent of the remaining oil).
Carbon dioxide (CO2) flooding is the most common enhanced oil recovery employed method in the United States today, but the limited availability of CO2 restricts its application in many regions. In over 80 percent of the geographic regions in the United States, CO2 is not readily available and no infrastructure exists for transporting or processing the gas. Chemical injection (alkali, surfactants, polymers and combinations thereof) offers an alternative method for improving oil recovery. Recent advances in alkali/ surfactant/polymer chemistry has made it possible to apply chemical flooding at costs well below those seen in historically. It is now estimated that ASP flooding can be a commercially viable alternative at oil prices in the range of $30-$50 per barrel. The incremental cost of chemicals is estimated to be in the range of $10-$15 per barrel of incremental oil recovered.
While laboratory work done to optimize the chemical formulation for the selected field demo site has shown that an ASP flood recovers over 90 percent of the residual oil in cores, the research team must translate these findings to the field. The site of this demonstration will be the Brookshire Dome Field, located ~30 miles west of Houston, where Layline Petroleum 1, LLC operates leases. A number of hydrocarbon formations are present above the caprock or draped over the edge of the piercement feature of the salt dome. The target for this project is the relatively shallow Oligocene Catahoula Sandstone.
It is anticipated that the findings from this field demonstration pilot will motivate operators to identify and test candidate reservoirs for ASP flooding and apply this technology to increase recovery factors in candidate reservoirs by up to 50 percent.
In addition, the work is expected to reduce the environmental impact of oil production in mature fields by cutting down on the volume of brine produced. The increase in incremental oil produced via ASP flooding will allow operators to produce mature oilfields for much longer than would otherwise be possible, resulting in a 10 to 30 percent reduction in the number of plugged and abandoned wells over the next decade.
Work on this project began in December 2009, and both the Project Management Plan and the Technology Status Assessment have been completed. The Project Management Plan consists of a work breakdown structure that concisely addresses the objectives and approach for each task with all major milestones and decision points. The Technology Status Assessment describes the state-of-the-art of the proposed technology.
Phase behavior testing was completed in June 2010, ahead of schedule. The inter-well tracer test in the pilot area is proceeding smoothly. Samples of water collected daily from 8 wells have been shipped to TIORCO's lab in Denver for analysis. Initial tests obtained from the tracer test show that the tracer has broken through into the wells to the north and east of the Martin 24. A spinner survey was run to determine the flow distribution in the Martin 24 (pilot injection well). The survey indicated that most of the flow is going into the top of the sand. Numerical simulations of the pilot area were conducted using UTCHEM to match the tracer test results and to simulate the ASP flood in the pilot area.
Injection and production rates from all EOR pilot wells are also being monitored on a daily basis. Clear patterns are emerging on the natural water drive in the reservoir. Results of the ongoing analysis or rates and the tracer test indicate that the surfactant-polymer injection scheme may have to be adjusted to account for the natural water drive.
Current Status (January 2011)
The tasks are described in detail below.
Field Characterization: Fluids and Rock The research team will collect formation fluid (brine and crude oil) and reservoir rock samples from the field and analyze them to obtain reasonable estimates of formation properties. This information will form the basis for an ASP flood recipe to be determined from systematic lab experiments, some of which have already been conducted. A detailed water analysis is available. The research team will measure the oil composition and will analyze components at the interface between the crude oil and the alkali using Gas Chromatography Mass Spectrometry (GCMS) to determine which components in the crude are responsible for reactivity with sodium carbonate. Interfacial tension measurements will also be conducted at the University of Texas.
Supporting Lab Phase Behavior Screening The researchers have performed preliminary phase behavior screening with a number of improved oil recovery (IOR) surfactants and crude oil and brine solutions. A propoxylated sulfate (C13-(PO)9-SO4) exhibited the most promising performance. Using an ethoxylated co-solvent (C12-15-(EO)12) improved the performance of the primary surfactant with respect to equilibration time and the absence of gels and macroemulsions. Mixtures with sodium carbonate (Na2CO3) exhibited shorter equilibration times as well as higher solubilization ratios, an indication of the reactivity of the crude oil. Sodium carbonate could be used to great advantage since it reduces surfactant adsorption and improves phase behavior. The extremely high solubilization ratios achieved with low surfactant concentrations indicate that this reservoir is an excellent candidate for ASP flooding. Additional phase behavior screening will be carried out to further refine these preliminary results.
Core Flooding Experiments and Simulation The research team will design and implement core floods as validation experiments for promising ASP recipes. Sidewall cores from the target sand (no whole cores) are available for this purpose. Berea sandstone will also be used with synthetic formation brine and crude oil. The researchers will monitor and analyze oil recovery and surfactant adsorption, and will investigate the effect of polymer and surfactant slug size, as well as the effect of a salinity gradient, on achieving optimal recovery efficiency. The team will simulate the design of the surfactant/polymer slug size and the fluid properties using UTCHEM, and will use these simulations to optimize the flood design by ensuring that the slug size is sufficient to ensure that the oil bank moves toward the producer without any adverse mobility control in the polymer bank.
Field Tracer Studies One of the keys to success in the application of ASP floods is knowledge of where the injected chemicals are going in the reservoir. The research team will employ inter-well tracer tests to monitor fluid movement by injecting an inorganic tracer (potassium iodide) into the proposed injection well (Martin 24). It is anticipated that due to natural groundwater flow in the lease, the tracer will preferentially flow from southwest to northeast. The researchers will superimpose the base groundwater flow on the injector induced flow profile to help quantify the impact of groundwater flow on the transport of the chemicals.
Field Planning and Pilot Design Based on the results of the experiments, the team will modify the water injection plant and design a mixture of surfactant slug and polymer drive fluids. TIORCO will assist in reconfiguring the injection system so that the polymer mixing and oil/water separation facilities can be set up appropriately. The injection well (Martin 24) will be squeeze cemented to ensure that the chemicals are only injected into the Catahoula Sand.
Field Implementation of Pilot Flood The researchers anticipate that injection of chemicals will commence after approximately 6 months of preliminary work. The operator will inject the surfactant, alkali, and polymer slug over approximately 1 to 2 months (this is approximate since it will depend on the slug size design and the injection rate). This will be followed by additional injection of polymer (for a period of approximately 2 to 4 months. The operator will taper off the polymer concentration and follow with chase brine at the tail end. Oil and water production rates in six adjacent producing wells will be monitored. It is anticipated that the proposed injection program will last for a period of six months, a much shorter injection time than typical pilot injection programs, primarily because the spacing between wells on the Martin lease is only 2 to 5 acres, and the permeability of the sands is high (several hundred milliDarcies).
Reporting and Data Analysis At the end of the injection program, the research team will compare the production data with the simulations conducted before the study to see if the simulations were able to predict the results, and make recommendations for future simulations. The team will prepare a draft final report that details the results and accomplishments of the complete project.
Project Start: December 1, 2009
Project End: November 30, 2011
DOE Contribution: $597,834
Performer Contribution: $628,460
RPSEA Martha Cather (email@example.com or 575-835-5685)
NETL Chandra Nautiyal (Chandra.Nautiyal@netl.doe.gov or 281-494-2488)
Layline Petroleum 1, LLC Chris Lewis (firstname.lastname@example.org or 713-465-4103)