AndreaBozzo/ceres-open-data-index huggingface dataset:
A REVIEW OF SLIMHOLE DRILLING

Slimhole drilling provides an opportunity to significantly reduce overall drilling costs for exploration and development of oil fields. This cost savings is especially important with the reduced capital budgets under current economic conditions in the oil industry. Cost reduction of 40 to 60% (or more in some cases) for exploration/appraisal wells and 25% to 40% (or more in some cases) for production/ injection wells comparing to conventional wells is possible. The savings are achieved by the use of smaller drilling rigs and/ or workover rigs, smaller locations, reduced casing sizes, reduced cutting volumes, less mud and cement, reduced fuel costs, and other costs associated with hole size.

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Laboratory Thermal Conductivity Measurements of Methane Hydrate and Hydrate-Sediment Mixtures Under Simulated In Situ Conditions

An understanding of the in situ thermal properties (e.g., thermal conductivity and thermal diffusivity) of gas hydrates in marine sediments is important for analyzing the effects of gas hydrate on thermal gradients, for accurately estimating temperatures at the depth of the bottom simulating reflector, and for calibrating empirical relationships with other physical properties, such as seismic wave speed. Previous laboratory thermal conductivity measurements on gas hydrates have primarily focused on propane and tetrahydrofuran hydrates and have sometimes been carried out at pressures and temperatures not representative of in situ marine conditions. In this study, we report on preliminary measurements of the thermal conductivity of pure methane gas hydrate and of gas hydrate and sand mixtures at simulated in situ conditions. We use the USGS-Menlo Park gas hydrate synthesis apparatus to form gas hydrate in a pressure chamber by mixing and subsequently heating sieved, granular ice (180-250 ?m) and cold, pressurized methane gas. For the experiments that include sediment, the gas hydrate is formed from a homogeneous mixture of equal volumes of 100 ?m quartz sand and granular ice. The synthesis technique yields well-characterized samples with porosities of 29% (pure methane hydrate) and 38.5% (sand and methane hydrate). Using the needle probe method of von Herzen and Maxwell, we have measured thermal conductivities of the samples at a range of pressures (13-30 MPa) and temperatures (-5 to 5?C) within the methane hydrate stability field. Preliminary results yield an estimated thermal conductivity of 0.81-0.87 W/mK for mixtures of quartz sand and methane hydrate and methane gas. In addition to providing control over hydrate and sediment mixture ratios, the measurement apparatus is also well suited for pore fluid injection. Using an effective medium approach applied to laboratory measurements, we can assess the effects of varying methane hydrate concentrations and pore fluid compositions on the thermal conductivities of a range of hydrate/sediment/pore fluid mixtures.

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DEVELOPMENT OF COST-EFFECTIVE  SURFACTANT FLOODING TECHNOLOGY

This research consists of the parallel development of a new chemical flooding simulator and the application of our existing UTCHEM simulation code to model surfactant flooding. The new code is based upon a completely new numerical method that combines for the first time higher order finite difference methods, flux limiters, and implicit algorithms. Early results indicate that this approach has significant advantages in some problems and will likely enable us to simulate much larger and more realistic chemical floods once it is fully developed. Additional improvements have also been made to the UTCHEM code and it has been applied for the first time to the study of stochastic reservoirs with and without horizontal wells to evaluate methods to reduce the cost and risk of surfactant flooding. During the first year of this contract, we have already made significant progress on both of these tasks and are ahead of schedule on both of them. We have found that there are indeed significant differences between the performance predictions based upon the traditional layered reservoir description and the more realistic and flexible descriptions using geostatistics. Our preliminary studies of surfactant flooding using horizontal wells shows that although they have significant potential to greatly reduce project life and thus improve the economics of the process, their use requires accurate reservoir descriptions and simulations to be effective. Much more needs to be done to fully understand and optimize their use and develop reliable design criteria

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SURFACTANT-ENHANCED ALKALINE FLOODING FOR LIGHT OIL RECOVERY

In this report, we present the results of our experimental and theoretical studies in surfactant-enhanced alkaline flooding for light oil recovery. The overall objective of this work is to develop a very cost-effective method for formulating a successful surfactant-enhanced alkaline flood by appropriately choosing mixed alkalis which form inexpensive buffers to obtain the desired pH (between 8.5 and 12.0) for ultimate spontaneous emulsification and ultralow interfacial tension. In addition, we have (1) developed a theoretical interfacial activity model for determining equilibrium interfacial tension, (2) investigated the mechanisms for  spontaneous emulsification, (3) developed a technique to monitor low water content in oil, and (4) developed a technique to study water-in-oil emulsion film properties. The results of the studies conducted during the course of this project are summarized below.

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RESPONSIVE COPOLYMERS FOR ENHANCED PETROLEUM RECOVERY

A coordinated research program involving synthesis, characterization, and rheology has been undertaken to develop advanced polymer systems which should be significantly more efficient than polymers presently used for mobility control and conformance. Unlike the relatively inefficient, traditional EOR polymers, these advanced polymer systems possess microstructural features responsive to temperature, electrolyte concentration, and shear conditions. Desired rheological behavior is accomplished by carefully controlling hydrophobic or ampholytic interactions between individual polymer chains. The polymers proposed circumvent major problems inherent in even the best conventional EOR polymers in which molecular weight is usually compromised in order to allow sufficient viscosity and uniform permeation without plugging the porous network. Additionally, conventional polymers are often poor mobility control agents in the presence of calcium, barium and sodium salts, precluding use in offshore recovery. By contrast, these advanced polymers would maintain high viscosities or behave as gels under low shear conditions and at elevated electrolyte concentrations expected in some reservoirs. At high fluid shear as, intermolecular aggregates would dissociate yielding low viscosity solutions, subsequently reducing potential problems of face-plugging and shear degradation during injection. Also, certain copolymer compositions have been developed which emulsify hydrocarbons and viscosity the making fluid. Initial laboratory experiments have demonstrated the promise of such systems in higher salt, higher temperature reservoirs or as potential surface/viscosijers to mobilize entrapped oil.

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Contracts for Field Projects Enhanced and Supporting Research on Enhanced Oil Recovery

The study will investigate two major areas concerning co-injecting an interfacial tension (IFT) reduction agent(s) and a mobility control agent into petroleum reservoirs. The first will consist of defining the mechanisms of interaction of an alkaline agent, a surfactant, and a polymer on a fluid-fluid and a fluid-rock basis. The second is the improvement of the economics of the combined technology. This report examines the effect of the addition of polymer to different combinations of alkaline agents and surfactants. Xanthan gum and polyacrylamide polymers were evaluated. In addition, the effect of alkali and polymer on the critical micelle concentration (CMC) of different surfactant types was investigated.

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IMPROVING RESERVOIR CONFORMANCE USING GELLED POLYMER SYSTEMS

The general objectives of the research program are to (1) identify and develop gelled polymer systems which have potential to improve reservoir conformance of fluid displacement processes, (2) determine the performance of these systems in bulk and in porous media, and (3) develop methods to predict their performance in field applications. The research focuses on three types of gel systems-an aqueous polysaccharide (KUSPI) that gels as a function of pH, polyacrylamide or xanthan crosslinked by Cr(Ill) and a polyacrylamide-aluminum citrate system. Work to date has focused primarily on development of a database, selection of systems, and work to characterize the gel/polymer physical properties and kinetics. The use of ester hydrolysis to control the rate of pH change of a gel system has been investigated and this approach to gel-time control shows promise. Extensive kinetic data were taken on the uptake of Cr(Ill) oligomers by polyacrylamide. A model was developed which describes very well the monomer uptake rates. The model described the dimer uptake data less well and the trimer uptake data poorly. Studies of the flow and gelation in rock materials have been initiated. A mathematical model of rock-fluid interaction during flow of high pH solutions has been developed.

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Effect of Elevated Methane Pressure on Methane Hydrate Dissociation Behavior at Temperatures Between 250 and 278 K

A comprehensive set of experiments performed at 0.1 MPa pressure between 204 and 289 K (Stern et al. {\it J. Phys. Chem. B} {\bf 2001}, {\it 105}, 1756; Circone et al., In {\it Gas Hydrates: Challenges for the Future}; Holder, G.D., Bishnoi, P.R., Eds., New York Academy of Sciences, New York; 2000; pp. 544-555) showed that methane hydrate dissociation rates were significantly depressed between 242 and 271 K. Above 271 K, the rate increased with increasing temperature. The dissociation rates at 1.0 and 2.0 MPa and at temperatures spanning the H$_{2}$O melting point have now been measured to determine if elevated pressures further depress these dissociation rates. Results will be used to optimize sI hydrate preservation during drill core retrieval in permafrost regions. Expected core retrieval conditions are at temperatures of 273 $\pm$ 5 K and at pressures that decrease from near 2.6 MPa (equilibrium pressure at 273 K) to 0.1 MPa. Pure, synthetic, porous methane hydrate samples were equilibrated at a temperature between 250 and 278 K and a methane pressure nominally 2 MPa above the hydrate equilibrium curve at that temperature. To begin an experiment, the pressure was rapidly decreased to 1.0 or 2.0 MPa (to P, T conditions outside of the methane hydrate stability field), then opened to a back pressure regulator, which can maintain a constant pressure to within 0.02 MPa of the set point. As the hydrate sample dissociated, the back pressure regulator released the methane to our custom-built flow meter, which measured the amount of released gas over time. Preliminary results at 2.0 MPa indicate that dissociation rates are wholly consistent with and slightly depressed below those at 0.1 MPa. At 0.1 MPa, the slowest dissociation rate occurs at 268 K, and at 2.0 MPa the average rate was slower (only 30% vs. 34% of the total methane released after 160 h at 2.0 vs. 0.1 MPa). Decreasing the pressure from 2.0 MPa to 1.0 MPa slightly increased the dissociation rate; returning to 2.0 MPa decreased the rate to near the prior value. At 0.1 MPa, similar reversible rate changes were obtained by varying the temperature from 268 to as low as 251 K. At 273 and 278 K, the dissociation rate at 2.0 MPa increases dramatically with increasing temperature. In the sample interior, the reaction temperature is buffered at 272.7-272.8 K, which is distinct from the H$_{2}$O ice point (273.0 K at 2.0 MPa). Experiments at 1.0 MPa are currently underway; initial results at 250 and 253 K indicate that dissociation rates are also depressed below those at 0.1 MPa.

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Piceance Basin/Rulison Field Case Study

The presence of natural fractures is required for the economic development of low-permeability reservoirs. Technology for reliably locating natural fractures before drilling ranks as one of industry's top goals. This presentation discusses the geomechanical approach that allows for the prediction of natural fracture clusters that control reservoir permeability and describes a case study of the application at the Rulison field in the Piceance Basin, Colorado. Fractured reservoirs often show characteristics indicating the presence of local natural fracture clusters which are a dense network of fractures that may differ in style and orientation from regional trends. Natural fracture clusters can be developed around local deformation events such as faulting or folding of the reservoir strata. Natural fracture clusters are generally responsible for zones of increased reservoir permeability beyond that caused by any uniformly distributed fracture system. Geomechanical models provide the means to predict the occurrences and characteristics of natural fractures around faults and thus allow a semi-quantitative prediction of fracture-related reservoir ?sweet spots.? A geomechanical method can predict the location and orientations of fault-related natural fracture clusters. The approach approximates faults as surfaces of displacement discontinuity in an elastic material and employs a 3D numerical code to calculate regions of stress concentrations that cause the natural fracture clusters. The case study is located in the Rulison field, Piceance basin, Colorado. There, production is from the tight-gas reservoir is the Cretaceous Williams Fork fluvial sands. The reservoir consists of massively stack fluvial sandstones with an average 12% porosity and permeability in the microdarcy range. The EUR ranges from .5 to 4.0 Bcf and can quickly change from a good to a sub-economic area in less than a mile. Using the geomechanical approach to delineate the area's ?sweet spots,? the predicted areas in the Rulison area are shown to correlate with regions of high permeability and significant EUR.

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DEVELOPMENT OF AN ADVANCED CUTTINGS TRANSPORT FACILITY AND OPTIMIZATION OF WELLBORE HYDRAULICS AT ELEVATED TEMPERATURES AND PRESSURES

Recently, a new research initiative, Advanced Cuttings Transport Study (ACTS), has been undertaken by the University of Tulsa. The ACTS research program calls for the construction of a new research facility, Advanced Cuttings Transport Facility (ACTF), which will allow investigation of cuttings transport with compressible drilling fluids at elevated temperature (200 ?F) and elevated pressure (2000 psi). The basic construction of the facility is completed and currently the loop is operational under elevated pressure Modification to the ACTF will continue by adding elevated temperature capability (1999), aeration and foam capability (2000), cuttings transfer capability (2001), pipe rotation capability (2002) and finally, elevation capability (2003). Development and utilization of the ACTF will offer the industry a unique insight into the complex processes that govern fluid flow during drilling and production phases. The Tulsa University ACTS research program will provide valuable information to optimize underbalanced drilling technologies.

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Application of High Resolution Seismic Imaging Methods for Fracture Quantification

Over the past several years as part of the Department of Energy's FETC fractured gas program, we have been developing and applying the use of high resolution seismic methods to define and map the permeable pathways in naturally fractured gas reservoirs. This work involves an iterative approach between theoretical, laboratory, modeling, controlled field work and large scale field work to develop and validate the appropriate seismic methods for not only determining the existence of fractures but for defining the fractures that control transport. The work has been focused on single and multiple component borehole sources in crosswell and single well configurations to record multicomponent data at frequencies from fifty to several kilohertz. Work to date shows that while surface methods provide broad characterization of fractures, borehole methods are necessary for providing the resolution necessary for inferring actual transport properties in fractured media. Although direct imaging of fractures is possible, other effects such as anisotropy, scattering and guided waves are also diagnostic of fracture characteristics in both velocity and amplitude analysis.

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Ruggedized Optical Fiber Sensors for Downhole Monitoring

Measurement and characterization of physical conditions in the downhole oil production environment will not only enable adoption of completion strategies based on expanded data from recovery processes, but also provide enhanced characterization of existing reserves. To this end, the objective of this research program is to develop and evaluate sensors for downhole measurement of pressure, temperature, volumetric flow, and acoustic waves (for seismic applications), and to develop technology to enable survival of the sensors over extended periods of time. This paper describes preliminary research in the development of a miniaturized fiber optic pressure sensor for downhole use.

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SCALING OF BUBBLE GROWTH IN A POROUS MEDIUM

The growth of a single gas cluster in a porous medium driven by a constant supersaturation is examined. Patterns and rates of growth are derived. It is shown that the growth pattern is not compact and changes from pure percolation to pure Diffusion-Limited-Aggregation (DLA) as the size of the cluster increases. The scaling of the cluster sizes that delineate these patterns, with supersaturation and diffusivity is presented for the case of quasi-static diffusion.

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Nonassociated Gas Resources in Low-Permeability Sandstone Reservoirs, Lower Tertiary Wasatch Formation, and Upper Cretaceous Mesaverde Group Uinta Basin, Utah

The U.S. Geological Survey recognizes six major plays for nonassociated gas in Tertiary and Upper Cretaceous low-permeability strata of the Uinta Basin, Utah. For purposes of this study, plays without gashater contacts are separated from those with such contacts (i.e., continuous-saturation accumulations).  Continuous-saturation accumulations are essentially single fields, so large in areal extent and so heterogeneous that their development cannot be properly modeled as field growth. Fields developed in gas-saturated plays are not restricted to structural or stratigraphic traps and they are developed in any structural position where permeability conduits occur such as that provided by natural open fractures. Other fields in the basin have gas/water contacts and the rocks are water-bearing away from structural culmination's. The plays can be assigned to two groups. Group I plays are those in which gas/water contacts are rare to absent and the strata are gas saturated. Group IT plays contain reservoirs in which both gas-saturated strata and rocks with gas/water contacts seem to coexist. Most units in the basin that have received a Federal Energy Regulatory Commission (FERC) designation as tight are in the main producing areas and are within Group I plays. Some rocks in Group II plays may not meet FERC requirements as tight reservoirs. However, we suggest that in the Uinta Basin that the extent of low permeability rocks. And therefore resources, extends well beyond the limits of current PERC designated boundaries for tight reservoirs. Potential additions to gas reserves from gas-saturated tight reservoirs in the Tertiary Wasatch Formation and Cretaceous Mesaverde Group in the Uinta Basin, Utah is 10 TCF (Group I sum of means of plays). If the potential additions to reserves in strata in which both gas-saturated and free water-bearing rocks exist (Group IT plays sum of means) are added to those of Group I plays, the volume is 13 TeF. Of this latter number, as much as 7.4 TCF will be recovered from Tertiary reservoirs and 5.8 TCF from Upper Cretaceous rocks.

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Detailed Evaluation of the West Kiehl Alkaline-Surfactant-Polymer Field Project and its Application to Mature Minnelusa Waterfloods

The combination of an interfacial tension agent and a mobility control agent has the potential to produce additional oil beyond a waterflood. The West Kiehl alkaline surfactant-polymer project is the most advanced application of this chemical enhanced oil recovery technique. The West Kiehl alkaline-surfactant-polymer flood was initiated in September 1987 as a secondary application after primary recovery. A preliminary analysis of the West Kiehl alkaline-surfactant-polymer flood indicates that incremental oil of 20% of the original stock tank oil in place will be produced above waterflooding. The cost of the incremental oil will be less than $2.50 per incremental barrel. A statistical analysis of approximately 120 Minnelusa oil fields in the Powder River Basin indicates that the original stock tank oil in place exceeds one billion barrels. If the enhanced oil recovery tec1mology implemented at West Kiehl field could be successfully applied to these fields, the potential incremental oil recovery would approach 200 million barrels.

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Microhole Drilling and Instrumentation

At Los Alamos, we have embarked upon a broad-based technology integration and development program. Our goal is to demonstrate the feasibility of obtaining geotechnical information in the subsurface by combining miniaturized conventional drilling technologies with contemporary electronics and advanced sensors assembled in very small-diameter borehole instrumentation packages. Using this approach, we expect to achieve a substantial reduction in the cost of oil and gas exploration and to increase the quantity and quality of subsurface data by using instruments specifically designed for data acquisition in microholes drilling at critical locations.

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IMPROVED AND ENHANCED OIL RECOVERY IN ILLINOIS THROUGH RESERVOIR CHARACTERIZATION

Grants from the Illinois Department of Energy and Natural Resources and the U.S. Department of Energy partially supported an integrated geological, geophysical, and engineering research project that defined the architecture, rock, mineral, and fluid properties of two hydrocarbon-bearing formations in 15 Illinois oil fields. This research has established the kinds of data and techniques needed for optimal reservoir characterization assessment and management in Illinois. Results of the project are presently being applied to improve reservoir management and recovery of hydrocarbons from Illinois Basin reservoirs. Improvement in oil recovery will continue, provided technology transfer is adequate, research is continued, and research results are effectively applied.

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INNOVATIVE TECHNIQUES FOR THE DESCRIPTION OF RESERVOIR HETEROGENEITY USING TRACERS

This is the final report of a three year research project on the use of tracers for reservoir characterization. The objective of this research was to develop advanced, innovative techniques for the description of reservoir characteristics using both single-well backflow and interwell tracer tests. Both chemical and miscible compositional reservoir simulators developed at The University of Texas were used as tools in this research and have been improved significantly. The application of the innovative tracer technology to the Elk Hills Naval Petroleum Reserve was also evaluated. The final accomplishments of this project substantially exceeded those promised in the original research proposal to DOE.

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