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Collaborating Authors
Open hole/cased hole log analysis
Abstract A new epithermal neutron tool, the Accelerator Porosity Sonde (APS), is being used for improved gas identification in Southwest Wyoming. The APS uses a high-yield electronic neutron source instead of the chemical source used in conventional neutron tools. It has five neutron detectors that provide both thermal and epithermal neutron detection, as well as borehole shielding, to obtain better porosity measurements. These improved measurements are not as sensitive to borehole environments and lithology effects and thus provide better gas determination. The tool has improved vertical resolution, which is helpful in the thin-bedded, shaly gas bearing sands of southwest Wyoming. This paper will discuss the tool features and compare examples of conventional neutron tools versus to this new technology and demonstrate improved identification of pay zones. Introduction Drilling activity has been very strong in the Wind River, Green River, and the Piceance Basins of Southwestern Wyoming and Northwestern Colorado (Figure 1) for the last several years due to the Tight Gas Sands tax credits prior to 1992, and the higher natural gas prices since then. These basins have been known to have very prolific gas producers from the thinly bedded sand and shale sequences. Unfortunately, conventional log evaluation has proven difficult in these gas reservoirs due to varying formation water resistivity, shale effects, and poor vertical resolution of conventional logging devices. This paper reviews new logging technology which results in better gas identification. Tool Features Density neutron logs incorporating the Compensated Neutron Log (CNL*) have long been used successfully in the study area to identify gas sands. The use of classic density - neutron crossover is the primary indicator of gas in this area and thus will be the focus of this paper. Resistivity measurements will not be presented or discussed, however they should be utilized whenever possible for complete evaluation of these reservoirs. As discussed in Olesen 1994, it is best to utilize an induction tool with a 1 ft vertical resolution in order to match the vertical resolution of the density and the neutron since this allows you to evaluate the same slice of the formation. P. 155
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.78)
- North America > United States > Wyoming > Wind River Basin (0.99)
- North America > United States > Wyoming > Green River Basin > Jonah Field (0.99)
- North America > United States > Utah > Green River Basin (0.99)
- North America > United States > Colorado > Piceance Basin > Williams Fork Formation (0.99)
Abstract A reliable reservoir description is essential to investigate various scenarios for successful field development. In this study, various new tools have been applied to frilly characterize the East Livingston Ridge Delaware reservoir. The Delaware formations in their slope/basin environment are difficult to characterize due to the channels in the submarine fans. Using well logs, a complex 3-D reservoir model composed of a channel through the bottom three layers of a seven layer model with one non-oil bearing zone was constructed to represent this complex depositional setting. Drastic changes in layer lithologies resulting in multiple oil/water contacts and varying water saturations required detailed log interpretation. The porosity logs were tuned with available sidewall core information. Log porosity was determined for each layer at each well and kriging was used to estimate the areal distribution of the porosity. Porosity-permeability correlations for each layer were developed from sidewall core data. The correlations were used to make an initial estimate of the interwell permeabilities. A production history match was not possible with the initial characterization of the reservoir. The production rates of the oil, gas, and water phases of each of the twenty-three wells in the East Livingston Ridge field and the pressure data were automatically history matched using a recently developed simulated annealing technique. The absolute and relative permeabilities of the layers were varied automatically during the history matching phase of the reservoir study. The larger scale properties resulting from the calibrated model were used to forecast the results of continued primary, infill drilling and/or waterflooding. Introduction Production from the upper Brushy Canyon zone in the Delaware Mountain Group began in the 1930's. P. 523
- North America > United States > Texas (0.68)
- North America > United States > New Mexico > Eddy County (0.34)
- North America > United States > Texas > Permian Basin > Delaware Basin > Two Freds Field (0.99)
- North America > United States > New Mexico > Permian Basin > Delaware Mountain Group Formation (0.99)
- North America > United States > New Mexico > Permian Basin > Delaware Basin > Avalon Field > Cherry Canyon Formation (0.99)
- (4 more...)
An Integrated Geologic and Engineering Reservoir Characterization of the North Robertson (Clearfork) Unit: A Case Study, Part 1
Doublet, L.E. (Texas A&M U.) | Pande, P.K. (Fina Oil and Chemical Company) | Clark, M.B (Fina Oil and Chemical Company) | Nevans, J.W. (Fina Oil and Chemical Company) | Blasingame, T.A. (Texas A&M U.)
BRIEF SUMMARY Infill drilling of wells on a uniform spacing, without regard to reservoir performance and characterization, must become a process of the past. Such efforts do not optimize reservoir development as they fail to account for the complex nature of reservoir heterogeneities present in many low permeability carbonate reservoirs. These reservoirs are typically characterized by:โLarge, discontinuous pay intervals โVertical and lateral changes in reservoir properties โLow reservoir energy โHigh residual oil saturation โLow recovery efficiency The operational problems we encounter in these types of reservoirs include:โPoor or inadequate completions and stimulations โEarly water breakthrough โPoor reservoir sweep efficiency in contacting oil throughout the reservoir as well as in the near-well regions โChanneling of injected fluids due to preferential fracturing caused by excessive injection rates โLimited data availability and poor data quality Infill drilling operations only need target areas of the reservoir which will be economically successful. If the most productive areas of a reservoir can be accurately identified by combining the results of geologic, petrophysical, reservoir performance, and pressure transient analyses, then this "integrated" approach can be used to optimize reservoir performance during secondary and tertiary recovery operations without resorting to "blanket" infill drilling methods. New and emerging technologies such as cross-borehole tomography, geostatistical modeling, and rigorous decline type curve analysis can be used to quantify reservoir quality and the degree of interwell communication. These results can be used to develop a 3-D simulation model for prediction of infill locations. In this work, we will demonstrate the application of reservoir surveillance techniques to identify additional reservoir pay zones, and to monitor pressure and preferential fluid movement in the reservoir. These techniques are: long-term production and injection data analysis, pressure transient analysis, and advanced open and cased hole well log analysis. The major contribution of this paper is our summary of cost effective reservoir characterization and management tools that will be helpful to both independent and major operators for the optimal development of heterogeneous, low permeability carbonate reservoirs such as the North Robertson (Clearfork) Unit. Introduction There are many complicated factors that will affect the successful implementation of infill drilling programs in heterogeneous, low permeability carbonate reservoirs such as the Clearfork/Glorieta of west Texas. Before we began this project, we conducted an extensive literature review to gain a better understanding of the producibility problems we face at the North Robertson Unit (NRU). Fortunately, these reservoirs have a long producing history and there is a large quantity of useful data available from case studies for primary, secondary, and tertiary operations in the Clearfork and other analogous reservoirs. In a 1974 case study concerning waterflooding operations at the Denver (San Andres) Unit, Ghauri, et al gave valuable insights concerning reservoir discontinuity, injector-producer conformance, and the effect of reservoir quality on reservoir sweep efficiency. Poor reservoir rock quality and the existence of discontinuous pay between injection and producing wells resulted in a recommendation to reduce nominal well spacing from 40 acres to 20 acres. An outcrop study on the San Andres was performed to verify reservoir discontinuity. Injection wells were completed and stimulated preferentially in an effort to flood only the continuous layers of the reservoir. The original peripheral injection design was converted to inverted nine-spot patterns in an effort to decrease the amount of water channeling and early water breakthrough via the most permeable members. P. 465
- Overview (1.00)
- Research Report > New Finding (0.67)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.68)
- Geology > Sedimentary Geology > Depositional Environment > Transitional Environment > Tidal Flat Environment (0.68)
- Geology > Mineral (0.67)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Borehole Seismic Surveying (0.93)
- Geophysics > Seismic Surveying > Seismic Modeling (0.67)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.45)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (27 more...)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- (4 more...)
- Information Technology > Modeling & Simulation (0.87)
- Information Technology > Data Science > Data Quality (0.34)
Abstract: Utilizing a newly developed low density zero wash tracer carrier (1.1 โ 1.5 gm/cc), acidizing treatments performed across large gross intervals consisting of thinly laminated carbonate/ sand stone reservoirs have been more accurately diagnosed with respect to placement efficiency. Multi-isotope tracer in combination with spectral gamma ray logs are used to evaluate and optimize acid treatments involving various diverting processes (i.e., rock salt/benzoic acid; ball sealers). Acid diverter treatments are evaluated using multi-tracer spectral gamma ray logs and subsequent efficiencies shown. A new low density tracer carrier that allows more effective, safer transport and placement of the isotopes was used and significantly improved the log interpretation. Example case histories of acid treatments evaluated using the new low density tracer carrier will be presented for treatments done in Utah, U.S.A.Acid treatments performed in long multi- perforated intervals using various diverting techniques were shown to have different coverage distribution than expected or indicated by treatment pressures. A new low density tracer carrier provides a clearer log definition where multi-isotopes are used to define acid stage and diverter stage distribution. Applications: Acid treatment diversion efficiency and effectiveness can be more accurately diagnosed with the new low density solid isotope carrier instead of previously used highly adsorptive liquid tracers. Actual treatment placement can be more specifically defined without problems caused by wellbore contamination using liquid tracers. Log definition was improved as well by using the new low density solid, as opposed to liquid tracers. A new tracer carrier to allow improved evaluation of acid treatment placement using diverters has been used and demonstrated to be more reliable than other solid or liquid carriers. A low density, specially sized, ceramic material was developed and used to contain multi-isotopes: P. 405
- North America > United States > Utah (0.35)
- North America > United States > Texas (0.28)
- North America > United States > Utah > Uintah Basin > Wasatch Formation (0.99)
- North America > United States > Utah > Uinta Basin > Altamont-Bluebell Field > Altamont Field (0.99)
- Well Completion > Acidizing (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Tracer test analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
Abstract Reservoir quality and response to stimulation vary significantly in the Frontier Formation. Available geological and engineering data have been integrated with a core study to better understand Frontier reservoir properties and stimulation response. Second Frontier reservoir quality is best developed in marine upper shoreface/bar and fluvial channel depositional systems. Lower shoreface sandstones are generally non-reservoir-quality material. Flow study results support the use of crosslinked gelled-water frac fluids from pH 4.0 to pH 10.5. The major potential completion problem identified in the Frontier is fines migration of mixed-layer illite/smectite clay. Analysis of production and stimulation data from the Church Buttes/Bruff area indicates that foam fracs may yield higher initial flow rates, but crosslinked gelled-water treatments result in higher ultimate recoveries. Introduction Frontier Formation gas on the Moxa Arch of Southwest Wyoming occurs in mixed moderate-permeability "conventional" and low-permeability "tight" reservoirs. The quality of Frontier reservoirs drilled and the effectiveness of stimulation treatments performed over approximately forty years have varied significantly due to exploration and production covering a large geographic area of heterogeneous reservoirs. Historically, prediction of Frontier reservoir quality has been a serious problem for operators and service companies alike. Reservoir quality in Frontier sandstones is dependent upon depositional environment and subsequent rock-pore network modification during burial history. Zone thicknesses, pore geometries, and clay suites are variable, implying differences in porosity/permeability levels and potential well completion problems. Attempts to better understand Frontier stimulation and production results are complicated by differences in stimulation treatments and rock-pore network variations that may be only subtly indicated on the wireline log signatures. Geological aspects of the project include examination of regional geology, depositional environments, texture, framework mineralogy, cements, clay mineralogy, and porosity types. The analytical techniques utilized were porosity/permeability measurement, acid solubility, scanning electron microscopy, energy dispersive spectrometry, X-ray diffraction, and liquid permeability testing. The engineering study included development of a 22 well routine core analysis database and a 500+ well stimulation and production history database. By integrating these studies, it becomes possible to draw some conclusions regarding reservoir quality, potential well completion problems, stimulation fluid selection, and production results. GEOLOGIC SETTING The Second Frontier Formation is a series of upper Cretaceous Age sandstone-siltstone-mudstone sequences deposited as eastward-prograding clastic wedges in the western Green River Basin. P. 715^
- Geology > Sedimentary Geology > Depositional Environment (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Mineral > Silicate (1.00)
- North America > United States > Wyoming > Church Buttes Field (0.99)
- North America > United States > Wyoming > Bruff Field (0.99)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Core analysis (1.00)
Abstract A method and underlying mathematical model are introduced for determining the size scaling and frequency sensitivity of mechanical properties. The method allows laboratory triaxial and ultrasonic data, as well as log data such as the dipole sonic log, or a subset of these, to be used for determining static moduli on a larger, scale. Applications are in hydraulic fracture design, in-situ stress estimation from logs, and wellbore/formation deformation studies. The model is based on soft discontinuities and inhomogeneities as the primary causes of scale effects in geologic media. Because of its basis in physical mechanisms, the model has the potential of being more widely applicable than if it were purely empirical. A computer program is developed to allow easy data reduction and application. Validation is performed with lab and field data at five different depths and rock types from a coalbed methane well. Introduction The properties of geologic media are scale-dependent. That is, measurements of properties on different size or time scales do not produce the same results. For example, a small core of coal usually has a higher compressive strength than a pillar of coal in a mine, even when the core is taken from the pillar itself. The problem is not simply one of averaging. If many cores are taken from the same pillar, the average of their strengths is lower than the strength of the pillar. In the geotechnical industry, it has long been recognized that rock deformability (defined as the ratio of stress to strain) is strongly size-dependent, and that larger sample sizes are usually associated with higher deformability. Furthermore, it consistently has been found that the more discontinuous (cracked or jointed) the rock, the more deformable and also more highly size-dependent it is. In some cases, moduli reductions with size of more than an order of magnitude have been observed. In the oil and gas industry, this effect generally has not been considered. To be sure, the effects is somewhat diminished by great depth of burial, but so long as rock is discontinuous and inhomogeneous, scale effects should not be considered negligible. Some progress has been made in the quantitative evaluation of static size-dependence in terms of joint or crack stiffnesses. Less has been done to separate the effects of time (in terms of measurement oscillatory frequency or dynamic rate) and size. Size effects and static-dynamic effects are related or overlie in many cases, and not considering this relationship is a potential source of confusion in data interpretation. As an example, Richards and Hustralid provide a data set from foundation studies at a nuclear power plant site. They perform several types of measurement of Young's modulus, including laboratory static (core-scale uniaxial), borehole static (deformation meter) and borehole dynamic (seismic). Table 1 summarizes these results. Comparing data columns one and two, the laboratory static values are seen to be about one order of magnitude larger than the borehole, as expected. However, the borehole dynamic values (column three) appear to agree approximately with the lab static. P. 615^
- Geology > Rock Type (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying (0.89)
- North America > United States > New Mexico > San Juan Basin (0.99)
- North America > United States > Colorado > San Juan Basin (0.99)
- North America > United States > Arizona > San Juan Basin (0.99)
- Well Drilling > Wellbore Design > Wellbore integrity (1.00)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- (2 more...)
Abstract A new directional gamma ray tool has been developed and is being incorporated into an innovative logging service. The service determines the azimuthal pattern of gamma ray emission from a completion material that has been tagged with a radioactive isotope. This paper discusses the interpretation of directional gamma ray logging data following hydraulic fracturing operations. By measuring the intensity of gamma rays emitted from tagged material placed in the induced fracture, the directional gamma ray measurement can be combined with auxiliary wellbore survey information to assist in the determination of propagation azimuth. Such results have a variety of applications - for example, designing a systematic well placement scheme to optimize reservoir drainage efficiency. Log examples derived from prototype tool measurements following hydraulic fracturing operations are presented and the analysis of the data is discussed. The interpretation of directional gamma ray data is adversely affected by damage to the near-wellbore region during fracturing operations. Data interpretation was found to be more consistent and reliable following micro-frac or mini-frac stress determination operations. In addition, where perforations were oriented in the direction of the anticipated fracture propagation, directional gamma ray data demonstrated an improvement in fracture efficiency. Introduction The theory of rock mechanics has been used to help predict the geometric parameters of fracture length, width and height. It has been established that the direction of fracture propagation is parallel to the maximum horizontal stress. The knowledge of the azimuthal direction of the hydraulic fracture propagation coupled with fracture modeling predictions can be used to design a well spacing and alignment pattern that would optimize the drainage of a reservoir. However, fracture propagation azimuth has been difficult and expensive to obtain and is not routinely used in development programs. Techniques for determining the orientation of hydraulic fractures include:An elastic strain relaxation measurements from oriented whole cores, characterization of borehole breakout features, borehole imaging using acoustic, electromagnetic and optical devices, borehole extensometer measurements made during micro-frac operations, passive and active seismic monitoring in both borehole and surface environments, measurements of surface displacements with tiltmeters and surveys of magnetic anomalies with magnetometers. It has long been thought that the direction of hydraulic fracture orientation could be determined by making azimuthal gamma ray measurements when radioactive tracer materials were placed in hydraulically induced fractures. More than a decade ago oriented gamma ray tools, which were originally used to orient perforating guns (used for perforating in tubingless completions), were adapted to make directional gamma ray measurements for fracture azimuth orientation. These early tools, including one used by HLS, used rather low efficiency Geiger-Mueller detectors. Statistical variations and low count rates from these detectors gave poor results. P. 95^
- North America > United States > Colorado (0.28)
- North America > United States > Texas (0.28)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Borehole Seismic Surveying (0.54)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
Abstract The fracture intensity log provides a means for recognizing and evaluating naturally occurring fractures in the wellbore. An analysis of the fractureintensity presentation can then be used in "pipe-setting" decisions. The fracture intensity log is based upon the shear wave properties derived from acoustic full waveform logs. Introduction Naturally occurring fractures play an integral part in the hydrocarbon potential of low permeability reservoirs. The natural fractures provide the porosity and permeability essential for a productive reservoir. The detection of these fractures may be accomplished through various wireline logging tools. Most wireline logging tools produce a measurement which provides a basis for inferring the presence of "fractures". The majority of these are limited in application because of the shallow depth of investigation of the tools, the sensing electrode must come in contact with the fracture, and most of the tools are confined to the open hole environment. The modern acousticfull wave form tools and the associated data processing techniques provide the means for recognizing and evaluating naturally occurring fractures in the open and case hole environment. Although there are several directions in analyzing waveform properties for fracture analysis, this paper focuses upon the shear wave travel time as a means for fracture evaluation. Several field examples show how the technique is applied. Statement of Definitions The acoustic full wave form logging tools propagate an acoustic signal into the borehole and surrounding formations. These wireline logging tools record a teach depth level an acoustic wave train composed of compressional, shear, normal mode, and tube waves. The depth of investigation of the acoustic wave represents an annular zone of the formation of about one wavelength in thickness. The wavelength is dependent upon the frequency of the logging tool and the velocity of the formation.
- Geology > Geological Subdiscipline > Geomechanics (0.93)
- Geology > Rock Type (0.71)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (22 more...)
Abstract A research study has been performed to improve the formation evaluation and reservoir description of the Frontier Formation located in the Green River Basin of southwestern Wyoming. Results of this study are presented which include the integration of data from an extensive wireline logging program. a comprehensive core analysis program, and well test production performance from two wells completed in the Frontier formation. performance from two wells completed in the Frontier formation. Features of several core analysis techniques are reviewed which were used to determine more accurately the in-situ porosity, water saturation, permeability and producibility from logs. This includes correcting core water saturation for mud filtrate invasion, correcting porosity and permeability to net overburden stress. and comparing porosity and permeability to net overburden stress. and comparing core data and log responses to quality control the laboratory core analyses. Log derived lithology was calibrated to that determined from cores using thin section point count and x-ray diffraction analysis. The log evaluation model, which was calibrated to core porosity, uses porosity and saturation exponents derived from porosity, uses porosity and saturation exponents derived from electrical property measurements on cores. A preliminary log derived permeability relationship has been developed and compared to that permeability relationship has been developed and compared to that obtained from production well tests. Introduction The Gas Research Institute has sponsored a research program to improve gas producibility in low permeability tight gas program to improve gas producibility in low permeability tight gas sand reservoirs. The GRI program initially focused in the Travis Peak and Cotton Valley Formations in the East Texas Basin. Subsequently, activity was shifted to other formations in different basins to transfer this technology. In 1989, the Frontier formation located in the Green River Basin of southwestern Wyoming was chosen for study by GRI. Presently, five wells in this basin are in this program. Four of these wells were evaluated in cooperation with operating companies in the area as shown in Figure 1. The tour cooperative wells are the Enron South Hogsback No. 13-8A, Terra Resources Anderson Canyon No. 3โ17, Texaco State of Wyoming U NCT-1 No. 1 and Wexpro Church Buttes No. 48. A fifth well, the Enron S.F.E. No. 4 (Staged Field Experiment) has recently been drilled and is still in the stage of being evaluated. In this program. GRI has funded the collection and analysis of conventional core, added to the typical wireline logging program used in the area, and added special completion, stimulation, and well tests. This paper focuses on the reservoir characterization of the South Hogsback well, but the Anderson Canyon well will be briefly described also. In the following discussion, the geologic setting of the Frontier Formation will be reviewed. This will be followed by a discussion of the petrographic and core analyses used in the South Hogsback well. Following this will be a discussion of the petrophysical analysis techniques used to calibrate the logs petrophysical analysis techniques used to calibrate the logs to the core analysis data. GEOLOGIC SETTING Depositional History The Upper Cretaceous Frontier Formation, a low-permeability gas reservoir in the Green River Basin in southwestern Wyoming, consists of marine and nonmarine facies that were deposited in a fluvial-deltaic depositional system. Much of the Frontier gas production occurs along the Moxa Arch, which is a broad intrabasin production occurs along the Moxa Arch, which is a broad intrabasin uplift parallel to the Overthrust Belt on the west side of the Green River Basin. The Second (lower) Frontier sandstones extend the length of the arch and contain the most prolific gas reservoirs. On the La Barge Platform at the north end of the Moxa Arch, the Second Frontier contains several sandstone "benches". The Second Bench, a laterally extensive marine shoreline sandstone, forms the main reservoir. The Second Frontier generally includes only one or two sandstones farther south along the Moxa Arch. The Second Frontier Interval formed in an eastward-prograding fluvial-deltaic depositional system, although a number of different coastal plain and nearshore marine facies have been recognized in core and outcrop. Most of the Second Frontier sandstone occurs in fluvial channel-fill and marine shoreface deposits. Rivers transported sand to the coast, where wave and wind-driven currents redistributed it along the shoreline. The shoreface sandstones form broad shore-parallel sheets, whereas the fluvial channel-fill sandstones form narrow belts oriented perpendicular to the shoreface. Along the south part of the Moxa perpendicular to the shoreface. Along the south part of the Moxa Arch, the fluvial channels commonly eroded into the underlying marine shoreface, creating amalgamated sandstone bodies. P. 717
- North America > United States > Wyoming (1.00)
- North America > United States > Texas (1.00)
- Geology > Sedimentary Geology (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- North America > United States > Wyoming > La Barge Platform (0.99)
- North America > United States > Wyoming > Green River Basin (0.99)
- North America > United States > Utah > Green River Basin (0.99)
- (7 more...)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Core analysis (1.00)
Abstract The new surge in drilling for coalbed methane gas has increased the need for quantitatively defining the grade of the various coal seams. The most common measurement for grading the coal seams has been through the use of formation bulk density. Empirical algorithms have been developed which use the formation bulk density to rank coal in terms of proximate analysis. Such empirical analysis has also made use of the Litho-Density (LDT*) with its Photo Electric Factor (PEF), neutron, and resistivity measurements in recent years. New methods need to be developed that do not depend on empirically derived algorithms so that the coal grading analysis can be significantly improved. The addition of data from the Geochemical Logging Tool (GLT*) to a LDT/CNL (Compensated Neutron Log) and resistivity logging suite offers such an opportunity. The GLT measures natural activation and prompt neutron capture gamma rays from which it produces measurements of the most abundant, and a few trace inorganic elements. This paper illustrates the need for development of a coal ranking and grading model based on the elemental analysis. For proper application of the model, it is necessary for it to be calibrated to core measurements (ie. rank of the coals). Introduction Traditional wireline logs such as resistivity, density, and neutron have been used in various coal basins to identify and grade the different coal seams. Table 1 shows log responses for coal. When these logs are used to interpret coals for their grade and rank, several assumptions are necessary, and usually the parameters used for one area of a basin need to be changed for a different area. First, an assumption is made that the mineral composition is constant and has a fixed density. P. 63
- North America > United States > Colorado (0.29)
- North America > United States > Texas (0.28)
- Geology > Rock Type > Sedimentary Rock > Organic-Rich Rock > Coal (1.00)
- Geology > Mineral (1.00)
- Geology > Geological Subdiscipline (1.00)
- North America > United States > New Mexico > San Juan Basin (0.99)
- North America > United States > Colorado > San Juan Basin (0.99)
- North America > United States > Arizona > San Juan Basin (0.99)
- North America > United States > Alabama > Black Warrior Basin (0.99)