DOE Selects New Research Projects to Help Improve U.S. Oil Production

23 Proposals Picked in Broad-Based Competition

With projects ranging from studies that will improve our knowledge of how oil flows through a reservoir to the development of new types of chemical polymers that help boost oil recovery from many U.S. fields, the U.S. Department of Energy is adding a diverse slate of new research projects to its program to enhance prospects for greater domestic oil production in the nation's energy future.

The Energy Department has selected 23 oil technology projects chosen from the first round of a broad-based solicitation the Department issued last December. These and other projects to be named later this year will form much of the core of the Energy Department's foreseeable petroleum research program.

The Energy Department's petroleum program, overseen by the National Petroleum Technology Office in Tulsa, is focused on slowing or perhaps halting the decline in production from U.S. oil fields by developing more effective and lower cost oil field production and environmental compliance technology.

The oil-related technology projects, organized in four technology topical areas, are:

Oil Technology: Critical Upstream Advanced Diagnostics & Imaging Technology
This topical area recognizes developing and refining technologies and methodologies that will improve resolution of reservoir rock, rock properties, and associated fluids at the pore-to-field scales is critical. That effort allows researchers to develop improved geologic and engineering models to more accurately quantify risk.

• Virginia Polytechnic Institute & State University, Blacksburg, VA, will integrate seismic, geologic and production data from Chevron's Coalinga Field in California to improve knowledge of how oil flows through the reservoir and enable design of more efficient recovery processes for increased production.

• University of Oklahoma, Norman, OK, will combine seismic images with physical, mechanical and acoustic measurements of weak rock types that are commonly damaged during drilling operations for identification of potential hazards and damage at oil production sites.

• University of Alabama, Tuscaloosa, AL, will integrate computer modeling of detailed rock and fluid information from carbonate reservoirs with well performance and seismic data, enabling identification of optimal fluid-flow paths that can increase recovery efficiency and extend reservoir life.

• University of Kansas Center for Research, Inc., Lawrence, KS, will develop an interactive Website offering assistance, software and tutorial support to oil researchers and operators in constructing real-time geo-engineering reservoir models for optimizing recovery processes and lowering operating costs.

• The University of Texas at Austin, Austin, TX, will integrate and periodically update seismic, well-log, production and geologic data into a unique, highly accurate computer model whose simulations of oil and gas flow will enable optimized reservoir management.

• Reservoir Engineering Research Institute, Palo Alto, CA, will treat reservoir rock surfaces of a gas well with special polymers that will prevent precipitation of liquid films that clog rock pores and promote the free flow of gas to the well head.

• Electromagnetic Instruments, Inc., Richmond, CA, will apply subsurface electromagnetic sensing technology to obtain detailed descriptions of reservoir rock makeup and subsurface fluid movement that will enable design of optimal CO2-water injection patterns for increased oil production.

• The University of Texas at Austin, Austin, TX, will study the size, clustering and connectivity of rock fractures for improved ability to plot how these features control the movement of reservoir fluids during injection or extraction, and enable design of optimal production processes.

• University of Tulsa, Tulsa, OK, will integrate seismic and production data with information on rock properties and their variations into reservoir models with improved ability to predict reservoir performance that can enable more efficient reservoir management, increased production and less costly operation.

Oil Technology: Reservoir Efficiency Processes
The reservoir efficiency processes topical area hopes to address the need to access oil not recoverable by conventional methods. Researchers hope to develop unconventional recovery methods such as gas flooding, heavy oil recovery, the use of chemicals, reservoir simulation or microbes.

• Stanford University, Stanford, CA, will combine X-ray technology with computer simulation and modeling to increase understanding of heavy oil thermal production mechanisms and enable design of more efficient processes for increased production and reduced operational expenses.

• Columbia University, New York, NY, will evaluate novel, cost-effective mixtures of surfactants that can be used under existing reservoir conditions and operations to reduce tension between oil and water in the reservoir, with minimal loss of chemicals, enabling increased production and lower operational costs.

• University of Utah, Salt Lake City, UT, will develop improvements to reservoir simulation, including affordable parallel reservoir simulation, performance monitoring, model updating, and a fractured-reservoir model, all implemented on the Internet for independent operator availability.

• The University of Texas at Austin, Austin, TX, will develop a new-generation chemical flooding simulator capable of modeling oil reservoirs with at least one million grid blocks, that will provide a whole new area of opportunities in advanced oil-recovery numerical investigations.

• University of Pittsburgh, Pittsburgh, PA, will develop technology to increase the viscosity of the dense, high-pressure CO2 used in carbon dioxide flooding to overcome its tendency to flow preferentially through permeable zones, bypassing significant volumes of oil.

• New Mexico Institute of Mining and Technology, Socorro, NM, will identify gel compositions that substantially reduce flow through rock fractures to reduce excess water production, and optimize gelant treatment that reduces permeability to water much more than that to oil to increase waterflood "sweep" efficiency.

• University of Southern Mississippi, Hattiesburg, MS, will develop two new classes of polymer that can control the flow behavior of water and oil in a reservoir: a soap-like polymer that will reduce surface tension to accelerate movement of oil through the reservoir; and a polymer whose flow can be reversed by pH or temperature to alter its capability to move or diffuse through the reservoir strata.

• The University of Texas at Austin, Austin, TX, will study the creation of foams during gas injection in oil wells, and the interactions of foam with chemicals, fluids and rock pores, to develop computer models with enhanced capabilities for predicting foam behavior, enabling improved oil recovery process design.

• Stanford University, Stanford, CA, will develop ultra-fast simulation tools for small-scale systems that can map the flow of injected gases through a reservoir and make field-scale predictions of injection performance, which will improve recovery process efficiency, increase production and lower operating costs.

Oil Technology: Drilling & Operations Technology Development and Demonstrations
This topical area includes several activities not implicit in this title: completion, stimulation and surface operations or sub-sea operations. The entire program is designed to provide the industry with economical and environmentally sound options to preserve and expand the critical infrastructure of the domestic oil supply.

• Conoco Inc., Houston, TX, will design, manufacture, install and test a self-contained subsea oil and gas processing system at an offshore field in the Gulf of Mexico that can substantially lower capital costs for deepwater oil and gas developments while improving well productivity and recovery.

Oil And Gas: Effective Environmental Protection
The present R&D effort in this topical area is on environmental technologies that provide new approaches to solving environmental compliance problems.

• New Mexico Institute of Mining and Technology, Socorro, NM, will develop two water treatment systems that will process water produced with oil into water with re-usable potential, reducing current disposal costs by as much as 90%.

• GE Energy and Environmental Research Corporation, Irvine, CA, will develop new sampling, analysis and measurement technologies for determining potentially significant sources of emissions subject to the new federal PM2.5 Fine Particulate air quality regulations, providing sound science-based data for realistic compliance standards.

• Kansas Corporation Commission, Lawrence, KS, will demonstrate the use of selected plants to remove, transfer or stabilize oilfield contaminants at oil and gas sites that have been damaged by the release of produced salt water or water/oil emulsion.

• Independent Petroleum Association of Mountain States, Denver, CO, will provide oil and gas operators with handbooks containing information necessary for successful compliance with the applicable federal and state environmental, health and safety rules and regulations in Arizona, Nebraska, Nevada, Oregon and Utah.

Funding amounts for these 23 projects are preliminary and subject to negotiation. More detailed project descriptions immediately follow.

-End of TechLine-

Program Contact:
Herbert A. Tiedemann, National Petroleum Technology Office, 918/699-2017, e-mail: htiedema@doe.npto.gov

PROJECT DESCRIPTIONS

Virginia Polytechnic Institute & State University (VPI), Blacksburg, VA, Seismic Determination of Reservoir Heterogeneity: Application to Characterization of Heavy Oil Reservoirs - Increasing production of the more than two billion barrels of heavy oil remaining in California's San Joaquin Valley depends on improved knowledge of the reservoir's fluid flow characteristics-the ability to move oil through reservoir strata. Between-well variations in the rock makeup and flow characteristics of these strata can impede the movement of oil and reduce production. Information on the variations, currently gained from analogous surface outcrops, similar reservoirs, or special drilling programs, is commonly inadequate for definitive analysis and simulation studies.

VPI researchers will work with Chevron Production Company in Chevron's West Coalinga field to develop advanced methods for inferring statistical properties about flow characteristics from seismic data, which are abundant in the region. The seismic techniques will be integrated with independent models based on geologic and production data from outcrops and well logs obtained as part of Chevron's current DOE-sponsored project in the field. The combination of VPI's seismic approach with Chevron's geologic information could increase the ability of companies operating in the San Joaquin Valley to optimize their recovery operations and increase production of heavy oil. VPI will provide $203,000 in cost sharing for the 36-month project, and DOE will provide federal funding of $450,000. The project contact is Matthias G. Imhof at 540-231-6004.

University of Oklahoma, Norman, OK, Acoustic Imaging and Mechanical Properties of Soft Rock and Marine Sediments - Withdrawal of oil and gas from reservoirs, and some drilling operations, can lead to severe and permanent damage to reservoir strata and compartments, destruction of downhole equipment, and loss of production and reserves with revenue losses amounting to billions of dollars. To augment industry's current use of seismic imaging techniques to evaluate potential for damage, University of Oklahoma researchers will investigate the acoustic signatures of weak rocks - such as high-porosity chalk, weakly cemented sandstones, and unconsolidated sands - as they are stressed and determine if seismic imaging can provide sufficient clues for the accurate prediction of potential damage.

The analysis will combine rock physics measurements with mechanical properties and deformation, using the University's Geomechanical Acoustic Imaging System to acquire both acoustic emission and acoustic velocity data during laboratory tests stressing rock to simulate reservoir rock conditions during a production operation. The completed study will provide operators with data on the characteristics of five problem rock types that geophysicists can combine with seismic images for pre-drill assessments of potential hazards at production sites or damage that may occur during reservoir operation, and imaging of potential damage to reservoir rocks already under production. The University of Oklahoma will provide $77,000 in cost sharing for the 24-month project, and DOE will provide federal funding of $290,000. The project contact is Thurman Scott at 405-325-2900.

University of Alabama, Tuscaloosa, AL, Integrated Geological-Engineering Model for Reef and Carbonate Shoal Reservoirs Associated with Paleohighs: Upper Jurassic Smackover Formation, Northeastern Gulf of Mexico - University of Alabama researchers, teaming with specialists from Texas A&M and McGill Universities and three independent oil producers--Longleaf Energy Group, Strago Petroleum and Paramount Petroleum Company--will conduct integrated, interdisciplinary research to characterize and model the reef and carbonate shoal reservoirs in the onshore Appleton and Vocation Fields in Monroe and Escambia Counties. Descriptions of reservoir architecture, pore structure and rock-fluid interactions, and a geoscientific and engineering digital database will be used to develop geologic models for improved computer simulation of the various reservoir types.

The simulation studies, combined with well performance analysis, will allow for prediction of fluid flow in the reef-shoal reservoirs. Seismic data will be integrated with the reservoir models for identification of reservoir properties using seismic attributes. The improved knowledge of the reservoirs and the focused field-wide reservoir management applications to these fields will improve recovery and should increase the life of these and similar domestic carbonate reservoirs in this and analogous sedimentary basins. The University of Alabama will provide $542,000 in cost sharing for the 36-month project, and DOE will provide federal funding of $754,000. The project contact is Ernest A. Mancini at 205-348-4319.

University of Kansas Center for Research, Inc., Lawrence, KS, Geo-Engineering Modeling Through Internet Informatics (GEMINI) - A website maintained by the University of Kansas center for Research will offer assistance in developing reservoir models. GEMINI is designed as an interactive, integrated Website for constructing real-time geo-engineering reservoir models. Information assembled from the Website or uploaded by the client will be analyzed with an extensive suite of web-accessed software using intelligent interfaces and tutorial support. Projects can range from regional to local, and span problems from simple to complex.

Reservoir characterization will encompass parameter definition, petrophysical modeling, and geo-engineering model development, all of which comprise components of advanced software applicable to specific aspects of the analysis. A tutorial component will assist the client in understanding theory and application of analytical software and in the operation of GEMINI. Petroleum industry companies participating with the University Center's Website will provide data and expertise to test the software and provide feedback, including participation in an annual review meeting. Increased skills in developing and using reservoir models will enable operators to optimize recovery processes, which can significantly lower operating costs and increase production. The University of Kansas will provide $362,000 in cost sharing for the 36-month project, and DOE will provide federal funding of $754,000. The project contact is W. Lynn Watney at 785-864-2184.

The University of Texas at Austin, Austin, TX, Integrated Approach for the Petrophysical Interpretation of Post- and Pre-Stack 3-D Seismic Data, Well-log Data, Geological information and Reservoir Production Data via Bayesian Stochastic Inversion - Computer models that can describe and predict the operational behavior of a reservoir provide valuable guidance for optimal oil and gas field operation. University of Texas researchers propose to develop a computer algorithm that will integrate 3-D seismic, well-log and reservoir production data and geological information for simulation of multiphase fluid flow under specified oil and gas field production regimes. This petrophysical model will employ sophisticated mathematical techniques that will govern the link between the model and the seismic parameters, which will be periodically updated with new measurements acquired throughout the production cycle.

The petrophysical model, comprising variables such as porosity, permeability and fluid saturation as they are distributed throughout the reservoir, will be tested, refined and transferred to industry through data sets provided by oil-producing companies. The University researchers believe that the ability of this model to fully integrate and exploit the information contained in the 3-D seismic data and the high vertical resolution available from well logs makes it unique in the industry. Its use will enable operators to increase production and lower operating costs through optimized reservoir management. The University of Texas at Austin will provide $286,000 in cost sharing for the 36-month project, and DOE will provide federal funding of $1.1 million. The project contact is Carlos Torres-Verdin at 512-471-4216.

Reservoir Engineering Research Institute, Palo Alto, CA, Wettability Alteration of Porous Media to Gas Wetting for Improving Productivity and Injectivity in Gas-Liquid Flows - In gas-liquid wells with low-permeability regimes, near-wellbore factors negatively affecting gas production and the ability to inject fluids include reservoir pressure, type of injection scheme, and presence of water. Reduced deliverability of gas results from gas and water condensing as liquid in gas-condensate or water-drive gas reservoirs. In both cases, the liquid spreads over mineral surfaces, clogging the reservoir rock pores, and preventing the flow of gas to the well head.

The three standard methods for combating these situations-fracture stimulation, surfactant injection, and CO2 stimulation-all require frequent and costly application. Based partly on previous work done for the Department of Energy, Reservoir Engineering Research Institute scientists propose to develop, test, and apply a novel method using special polymers to permanently alter the wettability of the reservoir's rock surfaces. By so altering the wettability of the wellbore surfaces there will be no liquid film flow on the rock surfaces and no clogging of pores. With the resultant free flow of gas, production will be increased and the costs of remedial treatment sharply reduced. The permanent nature of the treatment makes it very cost effective compared to the alternatives. The Reservoir Engineering Research Institute will provide $150,000 in cost sharing for the 36-month project, and DOE will provide federal funding of $598,000. The project contact is Dr. Abbas Firoozabadi at 650-326-9172.

Electromagnetic Instruments, Inc., Richmond, CA, Oil Reservoir Characterization and CO2 Injection Monitoring in the Permian Basin with Cross-well Electromagnetic Imaging - Recent application of CO2 injection has led to significantly increased production in Permian Basin wells. The technology is expensive, requiring costly injection and production infrastructure. However, careful characterization of the reservoir and tracking of subsurface fluid movement during production will provide guidance for optimal production process performance. In this project, Electromagnetic Instruments, Inc.(EMI) will apply its expertise in cross-well electromagnetic technology to optimize and test a system for reservoir characterization and CO₂ injection monitoring in a Permian Basin oil field. EMI's commercially developed systems in California have successfully performed in fields with steel-cased holes spaced up to 100 meters apart. In the Permian Basin, however, where steel-cased holes are separated by as much as 800 meters, a significant upgrade of the technology is required.

In the first phase of EMI's three-year project the transmitter power and receiver sensitivity will be upgraded. Pilot surveys will then be performed in Texaco's Vacuum oil field in New Mexico to obtain reservoir characterization data, locate water-saturated zones prior to waterflooding, and help plan CO2-water injection patterns. The final phase will comprise post-waterflood surveys to track fluid patterns, which will provide new data for reservoir simulation, help manage CO₂-water injection patterns, and ultimately increase production in Permian Basin operations. The upgraded technology can also provide reservoir characterization and waterflood monitoring for other recovery processes at many domestic sites and throughout the world. EMI will provide $383,000 in cost sharing for the 24-month project, and DOE will provide federal funding of $768,000. The project contact is Michael J. Wilt at 510-232-7997.

The University of Texas at Austin, Austin, TX, Advanced Technology for Predicting the Fluid Flow Attributes of Naturally Fractured Reservoirs from Quantitative Geologic Data and Modeling - Researchers at The University of Texas at Austin will develop new technology for the reliable prediction of fracture pattern attributes related to subsurface flow. A multidisciplinary team will focus on fracture size, clustering and connectivity, attributes that are difficult to measure, but which commonly control the movement of reservoir fluids during injection or extraction, and are therefore crucial to oil production.

The project will 1) determine the characteristic size below which natural fractures are completely mineralized and above which fractures preserve porosity and would be expected to be conduits for flow, 2) study geochemical controls on fracture mineralization and the effect of fracture size on porosity in natural fractures, 3) quantify fracture mechanics properties, particularly the growth of rock cracks and note how they may change over time, and 4) analyze fluid flow through fracture networks using a model that incorporates modification of fractures as the rock solidifies from sediment. Improvements in the ability to plot the control that fractures exert on reservoir fluid flow will provide oil operators with valuable information for designing optimal production processes. The University of Texas at Austin will provide $316,000 in cost sharing for the 36-month project, and DOE will provide federal funding of $837,000. The project contact is Jon Olson, 512-471-7375.

University of Tulsa, Tulsa, OK, Mapping of Reservoir Properties and Facies through Integration of Static and Dynamic Data - Accurate information on the distribution of reservoir permeability and porosity is essential for predicting oil production, locating bypassed oil, and optimizing reservoir management. Plausible reservoir models are relatively easy to generate using static data, such as core, log and seismic data, but they are much more difficult to generate using dynamic data such as transient pressures, saturations and flow rates. As a result, the uncertainty in reservoir properties is higher than it could be, making optimization of reservoir management correspondingly difficult. University of Tulsa researchers propose to develop computationally efficient automatic history-matching techniques that can accommodate both types of data for generating plausible reservoir models that can be used to quantify uncertainty in future reservoir performance and optimize reservoir management.

Because the flow properties of reservoir facies-regions of relatively uniform rock properties-can vary greatly, knowledge of their boundaries is of utmost importance for the prediction of reservoir performance. The ability to adjust these boundaries in the reservoir model, along with both static and dynamic data, and efficient computation of the sensitivity of production characteristics to changes in permeability or porosity are key technical issues that will be addressed in this project. Successful development of more efficient data management will provide oil operators with improved reservoir management techniques that can lead to increased production and more efficient, less costly operation. The University of Tulsa will provide $296,000 in cost sharing for the 36-month project, and DOE will provide federal funding of $577,000. The project contact is Dean S. Oliver at 918-631-3906.

Stanford University, Stanford, CA, Heavy and Thermal Oil Recovery Production Mechanisms - Heavy oil has considerable potential as an energy resource, but is underutilized because its increased viscosity renders it much more difficult to produce. Thermal processes are generally used for heavy oil production, because adding heat improves displacement efficiency. To increase understanding of heavy oil production mechanisms under both primary and enhanced modes of operation, Stanford researchers will use varied tools and techniques in the project, including X-ray and micromodels to improve imaging and visualization of multiphase flow, steam absorption, and gas and oil saturation.

The interaction of steam injection with fractures will be simulated for details of heat transfer and fluid exchange, permeability contrast between matrix, fracture and oil composition, and steam alteration of permeability. Simulation and analytical modeling of reservoir response to heating via horizontal wells will show how gravity forces can be used while minimizing the role of viscosity. Flow patterns studied in context with geologic factors to determine the success of recovery processes could reduce the computational size and time required for history matching and prediction of future recovery history. Success in these varied approaches to heavy oil operations will lead to more efficient processes, increased production, and reduced operational expenses. Stanford University will provide $328,000 in cost sharing for the 36-month project, and DOE will provide federal funding of $1.5 million. The project contact is Anthony R. Kovscek at 650-723-1218.

Columbia University, New York, NY, Behavior of Surfactant Mixtures at Solid/Liquid and Oil/Liquid Interfaces in Chemical Flooding Systems - Chemical flooding processes for oil production have been generally less than satisfactory, and their use has been limited by the high costs of the processes as well as significant loss of chemicals by adsorption on reservoir minerals and by precipitation. Columbia University researchers propose to develop cost-effective, improved and innovative chemical processes to increase recovery from domestic oil reservoirs efficiently. The researchers will evaluate novel, cost-effective mixtures of surfactants that can be used under existing conditions and operations with minimal loss of chemicals. The use of mixtures is advantageous in that their interfacial behavior can be synergistic (or antagonistic) and the effect can be manipulated by adjusting surfactant type and properties, such as mixing ratio and the order of addition (most past work in these systems used single surfactants, whereas current commercial systems are invariably mixtures). Additionally, Columbia's recent research indicates that surfactant mixtures can form aggregates-clumps of surfactant-with unusual behaviors that have the potential to minimize tension between oil and flooding media and also reduce adsorption of surfactants on reservoir rocks.

Columbia will perform a multifaceted study using advanced filtration, centrifuge, calorimetry and spectroscopic techniques. The major emphasis will be on the relationship between surfactant type, mixing ratio and shape, composition and structure of the surfactants. A model will be developed that can predict the formation and changes in surfactant aggregates in their mixtures. This integrated approach should help to develop a practical guide for designing surfactant flooding schemes that can effectively reduce interfacial tension between oil and flooding phase, which will increase production, and lower the adsorption loss of surfactant on reservoir rocks, which will reduce operational costs. Columbia University will provide $154,000 in cost sharing for the 36-month project, and DOE will provide federal funding of $580,000. The project contact is Professor P. Somasundaran at 212-854-2926.

University of Utah, Salt Lake City, UT, Online, Optimization-Based Simulation of Fractured and Nonfractured Reservoirs - Reservoir simulation using detailed descriptions of reservoir geologic and petrophysical properties is a primary tool used for better reservoir management. University of Utah researchers propose improvements to reservoir simulation that will enable independent producers to better utilize this sophisticated technology. To accomplish this task, a team of applied geoscientists, reservoir engineers and chemical engineers will pursue four goals:

• Incorporate the most modern numerical schemes in reservoir simulation algorithms and implement the simulator on large personal computer clusters to demonstrate affordable parallel reservoir simulation.

• Develop optimization-based reservoir simulators that can provide optimum reservoir operation, continuous performance monitoring and possibly automatic model updating based on reservoir history.

• Complete the University of Utah discrete-fracture model for an alternative production-level fractured reservoir model.

• Implement the entire package on the Internet (with adequate protection of intellectual property rights) so that the technology is available and accessible to a wide group of independents.

Successful completion of this project will open a new era of efficient reservoir operation and maintenance that could keep domestic marginal fields in operation for a considerably longer period. The University of Utah will provide $170,000 in cost sharing for the 36-month project, and DOE will provide federal funding of $680,000. The project contact is Milind D. Deo at 801-581-7629.

The University of Texas at Austin (UTA), Austin, TX, A New Generation Chemical Flooding Simulator - Modeling of advanced oil production processes to minimize the risk involved in development decisions is a critical element in efficient operation of modern reservoirs. Because of current oil industry needs for simulators with much more detailed geological, physical and chemical models requiring large volumes of computational work, there is a great need for both parallel computing and implicit algorithms. To satisfy this need, UTA researchers propose to develop a new generation chemical flooding simulator capable of efficient and accurate modeling of oil reservoirs with at least one million grid blocks. Based on the advanced framework already developed at UTA, the new unit will be a general-purpose reservoir simulator using state-of-the-art computing technology for high-resolution simulations of a variety of full field problems, something that is not currently available.

In this project UTA will build on the very successful research sponsored by DOE's National Petroleum Technology Office (NPTO) that produced UTCHEM, the most widely used general-purpose chemical simulator in the world. Because UTCHEM, in its current form, cannot run on parallel computers, simulations are limited to about 10,000 grid blocks. UTA will carry this research to a new level by adding appropriate chemical models and other new features to the implicit compositional EOS parallel simulator, developed at UTA in collaboration with the Argonne National Laboratory as one of NPTO's Natural Gas and Oil Technology Partnership projects. The combination of chemical and miscible-gas models will open a whole new area of opportunities in advanced oil-recovery numerical investigations, and provide significant improvements in reservoir management. The University of Texas at Austin will provide $233,000 in cost sharing for the 36-month project, and DOE will provide federal funding of $931,000. The project contact is Gary A. Pope at 512-471-3235.

University of Pittsburgh, Pittsburgh, PA, Inexpensive CO₂-Thickening Agents for Improved Mobility Control for CO2 Floods - An inherent disadvantage to the use of CO₂ flooding as an oil recovery process is the low viscosity of the CO2 at reservoir conditions. For maximum efficiency in moving the oil the CO2 should flow uniformly through the porous reservoir rock. Unfortunately, the reservoir strata are commonly variable in composition and texture, and the viscosity of CO2 is low relative to the oil. The result is preferential flow of "fingers" of CO₂ into highly permeable zones, leaving significant volumes of unproduced oil in the unswept, lesser permeable regions. This bypassed oil could be produced if the viscosity of the CO₂ was equal to the water or oil being displaced.

The objective of the University of Pittsburgh's research is to increase the viscosity of the dense, high-pressure CO2 to a level comparable to the oil in the formation, generally necessitating a 2-20 fold increase. Designing the thickener is a two-step process: identifying a highly soluble CO₂-soluble copolymer, and increasing the molecular weight of that copolymer to make it an effective thickener. Previous work by the Pittsburgh researchers produced novel copolymers composed of carbon, hydrogen and oxygen that are more soluble in CO2 than any other hydrocarbon polymer of equivalent length. The project will therefore concentrate on the second task, increasing the polymer molecular weight, optimizing the polymer composition, and incorporating functional polymer groups that will lead to intermolecular associations in solution. Successful formulation of an inexpensive, effective CO2 thickener will provide increased efficiency of CO2 flooding with resultant increase in oil production. The University of Pittsburgh will provide $260,000 in cost sharing for the 36-month project, and DOE will provide federal funding of $977,000. The project contact is Robert M Enick at 412-624-9649.

New Mexico Institute of Mining and Technology, Socorro, NM, Conformance Improvement Using Gels - Natural fractures in reservoir strata frequently cause excess water production by extending from production wells into aquifers, and can lower waterflood sweep efficiency by allowing injected fluids to channel directly between injection wells and production wells. New Mexico Tech proposes a three-year, two-task project to design gel treatments that can overcome these fracture-related problems. In Task 1, the researchers will identify gel compositions and conditions that substantially reduce flow through fractures which allow direct channeling between wells, while leaving secondary fractures open so that high fluid injection and production rates can be maintained. Gel propagation through fractures will be characterized as a function of fracture width, length and height, injection rate, gel composition, and temperature. The flow characteristics of the gels in fractures will be correlated with that in a viscometer.

Task 2 will employ coreflood studies and pore-level imaging using X-ray technology to focus on optimizing gelant treatment in fractured production wells, where the gel must reduce permeability to water much more than that to oil. The researchers will determine the correct mechanism(s) for disproportionate permeability reduction, identify the conditions that maximize the phenomenon, and find the materials and methods that make it predictable and controllable.

The results from both tasks will be integrated into an appropriate model for gelant placement and treatment sizing. The project will be provided with financial support and technical guidance by a New Mexico Tech consortium of at least eight oil companies. The technology developed will be transferred aggressively to the oil and gas industry through reports, project reviews, presentations at professional meetings, participation in regional workshops, and interaction with research counterparts in industry, government and academia. New Mexico Tech will provide $613,000 in cost sharing for the 36-month project, and DOE will provide federal funding of $1.2 million. The project contact is Randall S. Seright at 505-835-5571.

University of Southern Mississippi, Hattiesburg, MS, Stimuli-Responsive Copolymers with Enhanced Efficiency in Reservoir Recovery Processes - Researchers at Southern Mississippi's Center for Water Soluble Polymers, a facility funded largely by the National Petroleum Technology Office's Chemical Flooding Program, will develop a new type of polymer that can control the flow behavior of water and oil in a reservoir in response to pH, salt, temperature, or flow rate. These stimuli-responsive copolymers (SRP's) rely on carefully formulated chemical groups that sense changes in the surrounding medium and trigger appropriate responses, possibly even restoring original conformation when the stimulus is reversed. The SRP's can be injected in formulations designed for specific reservoir conditions, and in situ conditions can be altered during fluid injection cycles.

The Center will concentrate on two classes of SRP's: the first will be a soap-like polymer that will reduce surface tension to accelerate movement of oil through the reservoir; the second class will have controllable flow characteristics that can be reversed by pH or temperature to alter its capability to move or diffuse through the reservoir strata. After synthesizing the proposed SRP's, the researchers will determine their properties, including reversibility, measure their flow behavior, and tailor the fluids for desired in situ response. The completed products will be commercially feasible, cost-effective on a large scale, and environmentally attractive, since they are processed entirely in water. Widespread use of the new, innovative polymers should increase waterflood efficiency, lower operational costs, and significantly increase oil production. The University of Southern Mississippi will provide $352,000 in cost sharing for the 36-month project, and DOE will provide federal funding of $999,000. The project contact is Roger P. Hester at 601-266-4875.

The University of Texas at Austin (UTA), Austin, TX, Mechanistic Studies of Improved Foam EOR Processes - Nearly all Enhanced Oil Production in the U.S.-about 12% of total production-uses injection of gases, including steam, carbon dioxide and produced field gas. These processes are efficient in areas of the reservoir where the gas flows well, but the gas does not sweep efficiently through some parts of the reservoir, reducing oil recovery and limiting the number of such projects. Creating foams by injecting water and surfactant along with the gas offers one means of increasing the production potential of gas injection processes. UTA researchers propose a study of foam mechanisms that will lead to computer modeling with better predictive capabilities and improved process design.

UTA researchers will investigate pore-scale interactions between foam bubbles and polymers dissolved in water to determine if the polymer molecules strengthen or destabilize the foam. The mechanisms of trapping gas bubbles in the reservoir rock pores will be studied to determine how to accelerate foam's ability to divert gas flow to unswept regions and minimize the tendency to plug injection wells, which reduces the rate of liquid injection. Foam-generation mechanisms will be studied, with emphasis on the tendency of gas to migrate upwards across geological layers, bypassing much of the oil it is intended to move. Successful conclusion of these investigations will provide operators with better modeling of foam processes, improved process design, and wider application of foams in gas injection, which will increase recovery efficiency and production. The University of Texas at Austin will provide $198,000 in cost sharing for the 36-month project, and DOE will provide federal funding of $640,000. The project contact is Dr. William R. Rossen at 512-471-3246.

Stanford University, Stanford, CA, High Resolution Prediction of Gas Injection Process Performance for Heterogeneous Reservoirs - Because gas injection has the greatest potential for additional light oil recovery in U.S. reservoirs, Stanford researchers propose development of ultra-fast simulation tools that can be used to determine the composition of injected gases and make field-scale predictions of the performance of injection processes. To accomplish this objective, the researchers will determine the most appropriate methods for three-dimensional mapping of injected gas flow paths (streamlines) through the reservoir. Techniques for automatic generation of analytical solutions for one-dimensional flow along a typical flow path will be developed.

Improvements in the representation of physical mechanisms that govern displacement efficiency along a streamline will be pursued, and the limitations of the flow path approach will be established. Previous research under DOE grants indicate the feasibility of developing compositional simulation methods based on streamlines that will be orders of magnitude faster and significantly more accurate than conventional simulation methods. Success in this project will remove the principal barriers that limit the use of compositional simulation to small-scale systems and enable calculations at field scale that were previously impossible because they consumed far too much computer time and memory. Access to such improved simulation techniques will provide operators with significantly more efficient oil field operation, resulting in lower operating costs and increased production. Stanford University will provide $225,000 in cost sharing for the 36-month project, and DOE will provide federal funding of $1.1 million. The project contact is Franklin M. Orr at 650-723-2750.

Conoco Inc., Houston, TX, Development Program for Ultra Deepwater Hydrocarbon Production System - Conoco Inc. and its research team propose to design, manufacture, install and test a subsea oil and gas processing system at an offshore field in the Gulf of California. The innovative self-contained retrievable process module is designed to accommodate both incoming flowlines from subsea wells and outgoing product pipelines. The module is easily retrievable using diverless techniques for repair and maintenance, process reconfiguration or equipment upgrade.

Totally self contained, the module may be tested as a complete system prior to subsea installation. This also increases reliability by reducing interface problems. And because it is entirely electrically powered and controlled, it is virtually insensitive to water depth and suitable for ultra-deep water applications. The unit will substantially lower capital costs for deepwater oil and gas developments while improving well productivity and recovery. It can be the solution to recovering billions of barrels of oil from small deposits, making small fields economically viable, and can increase the reserve recovery of large fields. Conoco will provide $15 million in cost sharing for the 36-month project, and DOE will provide federal funding of $2 million. The project contact is Eddie P. Cousins at 281-293-2296.

New Mexico Institute of Mining and Technology, Socorro, NM, Modified Reverse Osmosis System for Treatment of Produced Water - Large volumes of salty water produced along with oil and gas present a serious waste management problem. The high cost of environmentally satisfactory disposal, generally by deep-well injection, can render many low-volume, marginal and other types of wells uneconomic to operate. To help prevent premature shutdown and abandonment of valuable oil and gas resources, New Mexico Tech (NMT) proposes to turn a problem into an asset-provide an economic means to process the produced water into "manufactured water," a new legal class of water with reusable potential being considered by the New Mexico legislature in 2000.

NMT researchers will test two systems that will avoid the high operating costs of current water treatment methods: a clay reverse-osmosis membrane that does not require costly chemical pretreatment, and a method of precipitating the dissolved salts for easy removal from the system. A trailer-mounted prototype unit will demonstrate the system at New Mexico wellheads. NMT projects economic installation and operating costs for the system, as low as $11,000 for installation and less than $9 per day operating costs for 100 barrel per day systems, a greater than 90% reduction in current disposal costs. Potential uses of the proposed system extend far beyond treatment of produced water, such as decreasing operating costs of desalination plants worldwide. New Mexico Tech will provide $285,000 in cost sharing for the 36 month project, and DOE will provide federal funding of $916,000. The project contact is Robert L. Lee at 505-835-5408.

GE Energy and Environmental Research Corporation, Irvine, CA, Development of Fine Particulate Emission Factors and Speciation Profiles for Oil and Gas-Fired Combustion Systems - GE Energy and Environmental Research Corporation (EERC) proposes development of new source-emissions characterization technology and critical data applicable to the new federal PM2.5 (Fine Particulate) air quality standards. These standards are expected to involve oil and gas industry production, refining, transportation/transmission, and end-user activities as potentially significant sources of emissions contributing to ambient particulate matter. EERC will use cutting-edge sampling and analysis methods to develop PM2.5 emission factors and particle-type chemical profiles for potential sources including gas-fired boilers, gas turbines, reciprocating engines, various boilers and generators used in oil production operations, and others. An improved measurement technology for PM2.5, especially the ultrafine condensable fraction that may be most responsible for adverse health effects, will be developed for adoption as a reference method. The project will also evaluate the health risk from certain substances such as organic compounds, nickel, vanadium, iron and other trace metals.

Complete, up-to-date, quality-assured data do not exist for all PM2.5-related emissions, and much of what does exist may be seriously flawed because of measurement artifacts. This project will greatly benefit the quality and reliability of resulting source emission standards affecting the oil and gas industry by ensuring they are based on sound science. Science-based regulations will promote realistic compliance standards and ensure that national resources expended by the oil and gas industry, its end users and the regulatory community achieve the maximum benefits to air quality. GE Energy and Environmental Research Corporation will provide $300,000 in cost sharing for the 36 month project, and DOE will provide federal funding of $822,000. The project contact is Dr. Glenn C. England at 949-859-8851.

Kansas Corporation Commission, Lawrence, KS, Study of Applied Phyto-Remediation Techniques Using Halophytes for Oil & Gas Brine Spill Scars - Release of produced salt water or water/oil emulsion has left numerous old oil and gas sites with surface scars denuded of vegetation and ravaged by deep erosion. These sites are an economic drain on both petroleum producers and state and federal budgets, typically requiring large expenditures for remediation, as well as on the local communities from adverse impacts on agriculture, community landfill capacity, and groundwater. The costs are significant and can be crippling to domestic petroleum operators, the petroleum sector, and producing states.

As a demonstration of a remediation technique, the Kansas Corporation Commission (KCC) proposes the establishment of a phyto-remediation project--the selective use of plants to remove, transfer or stabilize oilfield contaminants--at an eight-acre site in Butler County. As the party responsible for the property no longer exists, the remediation is being performed by the KCC. Rather than the costly and wasteful dig-and-haul-away-soil process typically used, KCC will test six varieties of salt-tolerant and salt-extracting plants (halophytes) for their potential to control erosion, improve vertical permeability of the soil to promote leaching of the salt, and actually remove the salt to the surface vegetation where it can be consumed by livestock or harvested and disposed offsite. Techniques most suited to the Kansas soil types and climate will be documented and distributed by the KCC in a Best Management Practices booklet to industry and landowners in Kansas and surrounding states. Efficient remediation of disturbed sites by the phyto-remediation technique will restore the land to both agricultural and oil and gas use, with attendant economic benefits. The Kansas Corporation Commission will provide $58,000 in cost sharing for the 24 month project, and DOE will provide federal funding of $191,000. The project contact is Doug Louis at 316-337-6241..

Independent Petroleum Association of Mountain States (IPAMS), Denver, CO, Environmental Health and Safety Handbooks for Nebraska, Utah, Arizona, Nevada and Oregon - Many of the operators of the more than 11,000 oil and gas wells in Arizona, Nebraska, Nevada, Oregon and Utah are small independent companies that lack adequate capabilities for complying with the numerous environmental regulations established by federal and state agencies. These companies rely generally on anecdotal interpretations from regional trade associations and environmental consultants for direction. IPAMS will prepare an Environmental, Health and Safety Handbook for the oil and gas industries (including tribal facilities) in those states that will provide operators with the information necessary for successful compliance with the applicable rules and regulations.

The handbooks, modeled on those previously prepared with DOE support for operators in Colorado, Wyoming, Montana, New Mexico, North and South Dakota, will outline major federal and appropriate state regulations, and are intended for staff and field-level personnel, but will also be useful as a quick reference for managers, regulatory personnel, and corporate attorneys. IPAMS will issue separate handbooks for Nebraska and Utah, and will combine coverage for Arizona, Nevada and Oregon in one book. Possession of this vital information by operators in the field and elsewhere will help attain compliance to the extensive array of regulations and avoid unnecessary expense resulting from unintended violations. IPAMS will provide $16,000 in cost sharing for the 10-month project, and DOE will provide federal funding of $65,000. The project contact is Raymond Gorka at 303-623-0987.