AndreaBozzo/ceres-open-data-index huggingface dataset:
On-line Optimization-Based Simulators for Fractured and Non-fractured Reservoirs

Oil field development is a multi-million dollar business. Reservoir simulation is often used to guide the field management and development process. Reservoir characterization and geologic modeling tools have become increasingly sophisticated. As a result the geologic models produced are complex. Most reservoirs are fractured to a certain extent. The new geologic characterization methods are making it possible to map features such as faults and fractures, field-wide. Significant progress has been made in being able to predict properties of the faults and of the fractured zones. Traditionally, finite difference methods have been employed in discretizing the domains created by geologic means. For complex geometries, finite-element methods of discretization may be more suitable. Since reservoir simulation is a mature science, some of the advances in numerical methods (linear, nonlinear solvers and parallel computing) have not been fully realized in the implementation of most of the simulators. The purpose of this project was to address some of these issues. {sm_bullet} One of the goals of this project was to develop a series of finite-element simulators to handle problems of complex geometry, including systems containing faults and fractures. {sm_bullet} The idea was to incorporate the most modern computing tools; use of modular object-oriented computer languages, the most sophisticated linear and nonlinear solvers, parallel computing methods and good visualization tools. {sm_bullet} One of the tasks of the project was also to demonstrate the construction of fractures and faults in a reservoir using the available data and to assign properties to these features. {sm_bullet} Once the reservoir model is in place, it is desirable to find the operating conditions, which would provide the best reservoir performance. This can be accomplished by utilization optimization tools and coupling them with reservoir simulation. Optimization-based reservoir simulation was one of the project goals. {sm_bullet} Providing remote access to the simulators developed was also one of the project objectives. The basic methods development is presented in Chapters 1-3. Development of a flux continuous finite element algorithm is presented with example calculations in Chapter 1. This is followed by discussion of three-dimensional, three-phase development in Chapter 2. A different numerical method, the mixed finite element method is presented in Chapter 3. Verification of the methods developed is described in Chapter 4. Introduction to fractured reservoir simulation is provided in Chapter 5 with an example of a fractured reservoir simulation study of a faulted reservoir in North Sea. Chapter six contains several examples of two dimensional simulations, while chapter 7 contains examples of three-dimensional simulation. In Chapter 8 optimization techniques are discussed. Chapter 9 contains a roadmap to use the remote programming interface for the fractured reservoir simulator.

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Ultra Deep Wave Equation Imaging and Illumination

In this project we developed and tested a novel technology, designed to enhance seismic resolution and imaging of ultra-deep complex geologic structures by using state-of-the-art wave-equation depth migration and wave-equation velocity model building technology for deeper data penetration and recovery, steeper dip and ultra-deep structure imaging, accurate velocity estimation for imaging and pore pressure prediction and accurate illumination and amplitude processing for extending the AVO prediction window. Ultra-deep wave-equation imaging provides greater resolution and accuracy under complex geologic structures where energy multipathing occurs, than what can be accomplished today with standard imaging technology. The objective of the research effort was to examine the feasibility of imaging ultra-deep structures onshore and offshore, by using (1) wave-equation migration, (2) angle-gathers velocity model building, and (3) wave-equation illumination and amplitude compensation. The effort consisted of answering critical technical questions that determine the feasibility of the proposed methodology, testing the theory on synthetic data, and finally applying the technology for imaging ultra-deep real data. Some of the questions answered by this research addressed: (1) the handling of true amplitudes in the downward continuation and imaging algorithm and the preservation of the amplitude with offset or amplitude with angle information required for AVO studies, (2) the effect of several imaging conditions on amplitudes, (3) non-elastic attenuation and approaches for recovering the amplitude and frequency, (4) the effect of aperture and illumination on imaging steep dips and on discriminating the velocities in the ultra-deep structures. All these effects were incorporated in the final imaging step of a real data set acquired specifically to address ultra-deep imaging issues, with large offsets (12,500 m) and long recording time (20 s).

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Mapping Alteration Caused by Hydrocarbon Microseepages in Patrick Draw area Southwest Wyoming Using Image Spectroscopy and Hyperspectral Remote Sensing

Detection of underlying reservoir accumulations using remote sensing techniques had its inception with the identification of macroseeps. However, today we find ourselves relying on the detection of more subtle characteristics associated with petroleum reservoirs, such as microseeps. Microseepages are the result of vertical movement of light hydrocarbons from the reservoir to the surface through networks of fractures, faults, and bedding planes that provide permeable routes within the overlying rock. Microseepages express themselves at the surface in an array of alterations and anomalies, such as chemical or mineralogical changes in overlying soils and sediments. Using NASA's Hyperion hyperspectral imaging sensors, this project has developed spectral and geochemical ground truthing techniques to identify and map alterations caused by hydrocarbon microseepages and to determine their relationships to the underlying geology in the Patrick Draw area of Southwest Wyoming. Training the classification of satellite imagery with spectral inputs of samples collected over previously defined areas of hydrocarbon microseepage resulted in the successful identification of an anomalous zone. Geochemical characteristics of samples that defined this anomalous zone were then compared to the remaining non-anomalous samples using XRD, ICP, spectroscopy and carbon isotope techniques.

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Altering Reservoir Wettability to Improve Production from Single Wells

Many carbonate reservoirs are naturally fractured and typically produce less than 10% original oil in place during primary recovery. Spontaneous imbibition has proven an important mechanism for oil recovery from fractured reservoirs, which are usually weak waterflood candidates. In some situations, chemical stimulation can promote imbibition of water to alter the reservoir wettability toward water-wetness such that oil is produced at an economic rate from the rock matrix into fractures. In this project, cores and fluids from five reservoirs were used in laboratory tests: the San Andres formation (Fuhrman Masho and Eagle Creek fields) in the Permian Basin of Texas and New Mexico; and the Interlake, Stony Mountain, and Red River formations from the Cedar Creek Anticline in Montana and South Dakota. Solutions of nonionic, anionic, and amphoteric surfactants with formation water were used to promote waterwetness. Some Fuhrman Masho cores soaked in surfactant solution had improved oil recovery up to 38%. Most Eagle Creek cores did not respond to any of the tested surfactants. Some Cedar Creek anticline cores had good response to two anionic surfactants (CD 128 and A246L). The results indicate that cores with higher permeability responded better to the surfactants. The increased recovery is mainly ascribed to increased water-wetness. It is suspected that rock mineralogy is also an important factor. The laboratory work generated three field tests of the surfactant soak process in the West Fuhrman Masho San Andres Unit. The flawlessly designed tests included mechanical well clean out, installation of new pumps, and daily well tests before and after the treatments. Treatments were designed using artificial intelligence (AI) correlations developed from 23 previous surfactant soak treatments. The treatments were conducted during the last quarter of 2006. One of the wells produced a marginal volume of incremental oil through October. It is interesting to note that the field tests were conducted in an area of the field that has not met production expectations. The dataset on the 23 Phosphoria well surfactant soaks was updated. An analysis of the oil decline curves indicted that 4.5 lb of chemical produced a barrel of incremental oil. The AI analysis supports the adage 'good wells are the best candidates.'The generally better performance of surfactant in the high permeability core laboratory tests supports this observation. AI correlations were developed to predict the response to water-frac stimulations in a tight San Andres reservoir. The correlations maybe useful in the design of Cedar Creek Anticline surfactant soak treatments planned for next year. Nuclear Magnetic Resonance scans of dolomite cores to measure porosity and saturation during the high temperature laboratory work were acquired. The scans could not be correlated with physical measurement using either conventional or AI methods.

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Performance Characteristics of an Extended Throat Flow Nozzle for the Measurement of High Void Fraction Multi-phase Flows

An extended throat flow nozzle has been examined as a device for the measurement of very high void fraction (a ³ 0.95) multi-phase flows. Due to its greater density and partial contact with the wall, the equilibrium velocity of the liquid phase appreciably lags that of the lighter gas phase. The two phases are strongly coupled resulting in pressure drops across the contraction and in the extended throat that are significantly different than those experienced in single-phase flow. Information about the mass flow rates of the two phases can be extracted from the measured pressure drops. The performance of an extended throat flow nozzle has been evaluated under multi-phase conditions using natural gas and hydrocarbon liquids at 400 and 500 psi. Two hydrocarbon solvents were used as the test liquids, Isopar MÒ (sp = 0.79) and Aromatic 100â (sp = 0.87). These data are compared to prior air-water data at nominally 15 psi. The high and low pressure data were found to be consistent, confirming that the temperature, pressure, and size scaling of the extended throat venturi are correctly represented. This consistency allows different sized devices to be applied under different fluid conditions (temperature, pressure, gas and liquid phase composition, etc) with confidence.

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Northern Cheyenne Reservation Coal Bed Natural Resource Assessment and Analysis of Produced Water Disposal Options

Coalbed methane (CBM) development in the Powder River Basin (PRB) is currently one of the most active gas plays in the United States. Monthly production in 2002 reached about 26 BCF in the Wyoming portion of the basin. Coalbed methane reserves for the Wyoming portion of the basin are approximately 25 trillion cubic feet (TCF). Although coal beds in the Powder River Basin extend well into Montana, including the area of the Northern Cheyenne Indian Reservation, the only CBM development in Montana is the CX Field, operated by the Fidelity Exploration, near the Wyoming border. The Northern Cheyenne Reservation is located on the northwest flank of the PRB in Montana with a total land of 445,000 acres. The Reservation consists of five districts, Lame Deer, Busby, Ashland, Birney, and Muddy Cluster and has a population of 4,470 according to the 2000 Census. The CBM resource represents a significant potential asset to the Northern Cheyenne Indian Tribe. Methane gas in coal beds is trapped by hydrodynamic pressure. Because the production of CBM involves the dewatering of coalbed to allow the release of methane gas from the coal matrix, the relatively large volume of the co-produced water and its potential environmental impacts are the primary concerns for the Tribe. Presented in this report is a study conducted by the Idaho National Engineering and Environmental Laboratory (INEEL) and the Montana Bureau of Mines and Geology (MBMG) in partnership with the Northern Cheyenne Tribe to assess the Tribe’s CBM resources and evaluate applicable water handling options. The project was supported by the U.S. Department of Energy (DOE) through the Native American Initiative of the National Petroleum Technology Office, under contract DEAC07- 99ID13727. Matching funds were granted by the MBMG in supporting the work of geologic study and mapping conducted at MBMG.

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Regulatory and Permitting Issues

As part of the West Coast Regional Carbon Sequestration Partnership (WESTCARB), Terralog Technologies USA, Inc., reviewed current state and federal regulations related to carbon dioxide capture and storage within geologic formations and enhanced carbon uptake in terrestrial ecosystems. We have evaluated and summarized the current and possible future permitting requirements for the six states that comprise the West Coast Regional Partnership. Four options exist for CO{sub 2} injection into appropriate geologic formations, including storage in: (1) oil and gas reservoirs, (2) saline formations, (3) unmineable coal beds, and (4) salt caverns. Terrestrial CO{sub 2} sequestration involves improved carbon conservation management (e.g. reduction of deforestation), carbon substitution (e.g., substitution for fossil fuel-based products, energy conservation through urban forestry, biomass for energy generation), and improved carbon storage management (e.g., expanding the storage of carbon in forest ecosystems). The primary terrestrial options for the West Coast Region include: (1) reforestation of under-producing lands (including streamside forest restoration), (2) improved forest management, (3) forest protection and conservation, and (4) fuel treatments for the reduction of risk of uncharacteristically severe fires (potentially with associated biomass energy generation). The permits and/or contracts required for any land-use changes/disturbances and biomass energy generation that may occur as part of WESTCARB's activities have been summarized for each state.

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Supercement for Annular Seal and Long-Term Integrity in Deep, Hot Wells "Deep Trek"

The purpose of this project is to formulate a ''Supercement''designed for improving the long-term sealing integrity in HPHT wells. Phase I concentrated on chemistry studies and screening tests to design and evaluate Portland-based, hybrid Portland, and non-Portland-based cement systems suitable for further scale-up testing. Phase II work concentrated on additional lab and field testing to reduce the candidate materials list to two systems, as well as scale up activities aimed at verifying performance at the field scale. Phase II was extended thorough a proposal to develop additional testing capabilities aimed at quantifying cementing material properties and performance that were previously not possible. Two materials are being taken into Phase III for field testing and commercialization: {lg_bullet} Highly-expansive cement (Portland-based), patent pending as ''Pre-Stressed Cement''{lg_bullet} Epoxy Resin (non-Portland-based), patent pending In Phase II, significant effort was expended on scaling up the processes for handling resin in the field, as it is quite different than conventional Portland-based cements in mixing, personnel protection, and cleanup. Through this effort, over fifty (50) field jobs were done at a variety of temperatures and depths, most with excellent results. Large-scale field testing was less relevant with Pre-stressed Cement, because the materials and surface processes do not vary from those that have been developed for conventional Portland materials over the last eighty (80) years. The formulation is quite unique, however, and performs very differently than conventional Portland cements downhole.

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Application of Time-Lapse Seismic Monitoring for the Control and Optimization of CO2 Enhanced Oil Recovery Operations

The ''Application of Time-Lapse Seismic Monitoring for the Control and Optimization of CO{sub 2} Enhanced Oil Recovery Operations''project is investigating the potential for monitoring CO{sub 2} floods in carbonate reservoirs through the use of standard p-wave seismic data. This project will involve the use of 4D seismic (time lapse seismic) to try to observe the movement of the injected CO{sub 2} through the reservoir. The differences between certain seismic attributes, such as amplitude, will be used to detect and map the movement of CO{sub 2} within the reservoir. This technique has recently been shown to be effective in CO{sub 2} monitoring in EOR projects such as Weyborne. The project is being conducted in the Charlton 30/31 field in northern Michigan Basin which is a Silurian pinnacle reef that has completed its primary production. This field is now undergoing enhanced oil recovery using CO{sub 2}. The CO{sub 2} flood was initiated the end of 2005 when the injection of small amounts of CO{sub 2} begin in the A1 Carbonate. This injection was conducted for 2 months before being temporarily halted in order for pressure measurements to be conducted. The determination of the reservoir's porosity distribution is proving to be a significant portion of this project. In order to relate the differences observed between the seismic attributes seen on the multiple surveys and the actual location of the CO{sub 2}, a predictive reservoir simulation model had to be developed. From this model, an accurate determination of porosity within the carbonate reservoir must be obtained. For this certain seismic attributes have been investigated. The study reservoirs in the Charlton 30/31 field range from 50 to 400 acres in size. The relatively small area to image makes 3-D seismic data acquisition reasonably cost effective. Permeability and porosity vary considerably throughout the reef, thus it is essential to perform significant reservoir characterization and modeling prior to implementing a CO{sub 2} flood to maximize recovery efficiency. Should this project prove successful, the same technique could be applied across a large spectrum of the industry. In Michigan alone, the Niagaran reef play is comprised of over 700 Niagaran reefs with reservoirs already depleted by primary production. These reservoirs range in thickness from 200 to 400 ft and are at depths of 2000 to 5000 ft. Approximately 113 of these Niagaran oil fields have produced over 1 million bbls each and the total cumulative production is in excess of 300 million bbls and 1.4 Tcf. There could potentially be over 1 billion bbls of oil remaining in reefs in Michigan much of which could be mobilized utilizing techniques similar to those employed in this study.

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Preliminary Geologic Characterization of West Coast States for Geologic Sequestration

Characterization of geological sinks for sequestration of CO{sub 2} in California, Nevada, Oregon, and Washington was carried out as part of Phase I of the West Coast Regional Carbon Sequestration Partnership (WESTCARB) project. Results show that there are geologic storage opportunities in the region within each of the following major technology areas: saline formations, oil and gas reservoirs, and coal beds. The work focused on sedimentary basins as the initial most-promising targets for geologic sequestration. Geographical Information System (GIS) layers showing sedimentary basins and oil, gas, and coal fields in those basins were developed. The GIS layers were attributed with information on the subsurface, including sediment thickness, presence and depth of porous and permeable sandstones, and, where available, reservoir properties. California offers outstanding sequestration opportunities because of its large capacity and the potential of value-added benefits from enhanced oil recovery (EOR) and enhanced gas recovery (EGR). The estimate for storage capacity of saline formations in the ten largest basins in California ranges from about 150 to about 500 Gt of CO{sub 2}, depending on assumptions about the fraction of the formations used and the fraction of the pore volume filled with separate-phase CO{sub 2}. Potential CO{sub 2}-EOR storage was estimated to be 3.4 Gt, based on a screening of reservoirs using depth, an API gravity cutoff, and cumulative oil produced. The cumulative production from gas reservoirs (screened by depth) suggests a CO{sub 2} storage capacity of 1.7 Gt. In Oregon and Washington, sedimentary basins along the coast also offer sequestration opportunities. Of particular interest is the Puget Trough Basin, which contains up to 1,130 m (3,700 ft) of unconsolidated sediments overlying up to 3,050 m (10,000 ft) of Tertiary sedimentary rocks. The Puget Trough Basin also contains deep coal formations, which are sequestration targets and may have potential for enhanced coal bed methane recovery (ECBM).

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An Overview of Geologic Carbon Sequestration Potential in California

As part of the West Coast Regional Carbon Sequestration Partnership (WESTCARB), the California Geological Survey (CGS) conducted an assessment of geologic carbon sequestration potential in California. An inventory of sedimentary basins was screened for preliminary suitability for carbon sequestration. Criteria included porous and permeable strata, seals, and depth sufficient for critical state carbon dioxide (CO{sub 2}) injection. Of 104 basins inventoried, 27 met the criteria for further assessment. Petrophysical and fluid data from oil and gas reservoirs was used to characterize both saline aquifers and hydrocarbon reservoirs. Where available, well log or geophysical information was used to prepare basin-wide maps showing depth-to-basement and gross sand distribution. California's Cenozoic marine basins were determined to possess the most potential for geologic sequestration. These basins contain thick sedimentary sections, multiple saline aquifers and oil and gas reservoirs, widespread shale seals, and significant petrophysical data from oil and gas operations. Potential sequestration areas include the San Joaquin, Sacramento, Ventura, Los Angeles, and Eel River basins, followed by the smaller Salinas, La Honda, Cuyama, Livermore, Orinda, and Sonoma marine basins. California's terrestrial basins are generally too shallow for carbon sequestration. However, the Salton Trough and several smaller basins may offer opportunities for localized carbon sequestration.

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