1,185 research outputs found
Shale Gas and the EU Internal Gas Market: Beyond the Hype and Hysteria. CEPS Working Document No. 369, September 2012
No full textThis paper analyses the interplay between shale gas and the EU internal gas market. Drawing on data presented in the 2012 International Energy Agency’s report on unconventional gas and additional scenario analyses performed by the Joint Research Centre, the paper is based on the assumption that shale gas will not fundamentally change the EU’s dependence on foreign gas supplies. It argues that attention should be shifted away from hyping shale gas to completing the internal gas market. Two main reasons are given for this. First, the internal gas market is needed to enable shale gas development in countries where there is political support for shale gas extraction. And second, a well-functioning internal gas market would, arguably, contribute much more to Europe’s security of supply
than domestic shale gas exploitation. This has important implications for the shale gas industry. As it is hard to see how subsidies or exemptions from environmental legislation could be justified, shale gas development in Europe will only go ahead if it proves to be both
economically and environmentally viable. It is thus up to the energy industry to demonstrate that this is the case
Reservoir Characterization and Chemostratigraphy of the Goddard Shale in the South Central Oklahoma Oil Province
No full textThe Goddard Shale of the South Central Oklahoma Oil Province, or SCOOP, has become a formation of interest in recent years. However, there is a paucity of published information in regards to this formation. Therefore, the purpose of this study is to provide a reservoir characterization of the formation by means of core description of lithofacies, chemostratigraphic trends, chemofacies, mineralogy, and porosity. Additionally, this study sets out to define the appropriate nomenclature for the formation, which has not been defined in a formal sense.
Descriptions and chemostratigraphic work were carried out on two cores taken from the formation. One was taken from its uppermost organic-rich bench, which this study refers to as the Boatwright Shale, and the other core was taken from the lowermost organic-rich bench, which this study refers to as the Velma Shale. Both cores are predominantly siliceous-argillaceous with carbonate content being restricted to debris flows from the inner shelf. Each core contains its own parasequence set with higher-order intervals superimposed, most easily defined by the changes in continental input by means of trace elemental proxies, although each has a different manifestation of the effects of rising sea levels.
In analyzing the porosity of the formation, this study compares three different techniques: 1) FESEM image analysis utilizing ion beam milling, 2) FESEM image analysis utilizing freshly broken shale surfaces, and 3) a method that relies upon calculated matrix density based upon Rock-Eval and XRD mineralogy. Of the three, the broken surfaces technique appears to have produced the most accurate results due to the large margin of error in the calculated density technique and the general lack of inorganic porosity in the ion beam milling technique. Measured porosity values range from 7.04% to 13.11%
Comprehensive Reservoir Characterization of the Woodford Shale in Parts of Garfield and Kingfisher Counties, Oklahoma
No full textThis research is a comprehensive characterization of the Woodford Shale within an area of six townships and ranges located at the boundary of Garfield and Kingfisher Counties in Oklahoma.
The methods of the Woodford Shale reservoir characterization include: sequence stratigraphy interpretation, well log interpretation, X-ray diffraction (XRD) and X-ray fluorescence (XRF) analysis on drill cuttings, Rock-Eval organic geochemistry analysis and microseismic interpretation.
The interpretation results of these methods provided detailed characteristics of the Woodford Shale. Seven third order parasequences were identified within the Woodford based on the well logs. The lower parasequences were more likely to be deposited where there was a paleo-topographic low, and there is an inverse relationship of thickness between the Woodford and Sylvan Shale. The mineral composition obtained from drill cuttings shows that the Woodford Shale has high clay content mainly composed of illite and kaolinite, moderate quartz content derived both from biogenic radiolaria and detrital quartz. The percentage of quartz highly affects the brittleness of the formation and ultimately affects the efficiency of hydraulic fracturing. From the thin section analyses, there are five types of Woodford Shale cuttings identified based on different mineral composition and internal structure. The chemostratigraphic analysis based on the horizontal well XRF profile defined 12 chemofacies. The 12 chemofacies were interpreted and related to sequence stratigraphy and sea level fluctuations. The XRF datasets are also correlated with XRD-derived mineral data and calculated brittleness. The organic geochemistry aspect indicated that Woodford is an organic-rich shale with high TOC value and it is within the oil thermal maturation window due to the shallower burial depth than the Woodford in the Anadarko Basin.
The microseismic data interpretation of one horizontal well indicates that there is a relationship between the sequence stratigraphic framework and the microseismic event distribution. In the highstand system tract (brittle zone), the fractures are more prone to stay within the target formation and grow horizontally to enhance the fracturing efficiency. When the stimulation occurs within the transgressive system tract (ductile zone), the perforation energy will be absorbed by the formation and reduce the fracturing efficiency. From the image log and microseismic distribution patterns, the local stress field was interpreted. The maximum horizontal stress direction is N80E. To get better fracturing effect in the future, nearby well is should be drilled perpendicular to the maximum horizontal stress direction, or N10W.
Overall, the Woodford Shale in the study area is a high potential and high quality unconventional reservoir for exploration and development. The well placement and fracturing plan design need to consider the sequence stratigraphy and heterogeneity within the reservoir in order to enhance drilling efficiency and hydrocarbon production
Regional variability of Caney Shale elemental composition, mineralogy, and petrophysical properties, Ardmore Basin, Oklahoma
No full textThe Mississippian-age Caney Shale of the Ardmore Basin, Oklahoma, consists of four chemofacies based on geochemical analyses of well drill cuttings. Chemofacies 1 and 3 represent a dominant detrital source into the basin, and chemofacies 2 is associated with periods of shallow-water conditions favorable to carbonate mineral formation. Chemofacies 4 represents intervals that are interpreted to have formed by reducing-bottom water conditions during deposition, with pyrite formation in an anoxic setting. The elemental proxies used to indicate carbonate minerals and detrital fluxes correlate with X-ray diffraction (XRD) derived mineralogical analyses. Based on XRD, the Caney Shale is primarily composed of mixed-clays, quartz, and carbonate minerals. The mixed-clay fraction consists of illite and kaolinite, while the carbonate fraction is composed of calcite and ankerite. These results are also consistent with ρmaa-Umaa mineralogical analysis, constrained by XRD results, which revealed 3 rock types: mixed-clays, quartz, and carbonate. Rock-type models and vertical proportion curves illustrate an abundance of carbonate deposits within the central Ardmore Basin, suggesting a shallow-water environment and likely multiple shorefaces delivering sediment across the basin. A decreasing upward GR log response paired with an increasing upward carbonate abundance can be interpreted as transgressive sequences that correspond to 4 stratigraphic zones within the Caney Shale. Chemofacies also correlate with the transgressive sequences, suggesting that chemofacies are related to deposition. 3D total porosity models show an average porosity of approximately 20% per zone of the Caney Shale, with maximum porosity values of 61% occurring in Zone 4. Brittleness index models show brittleness within the quartz rock type, and greater ductility within the mixed clay rock type. This basin-scale characterization provides an understanding of Caney Shale elemental composition, mineralogy, and petrophysical properties and their regional variability
Oil shale symposia proceedings index: 1964-82
No full textCompiled by Gary L. Baughman and Christopher H. Cox.Includes illustrations.From the Forward: Over the 18 years that the Colorado School of Mines Oil Shale Symposia have been presented in conjunction with the Colorado School of Mines Research Institute (1964-65), the American Institute of Mining, Metallurgical, and Petroleum Engineers (1966-74), and the Laramie Energy Technology Center (1978 to 1982), many volumes of information have been presented on the geology, mining, processing, environmental, and socioeconomic aspects of oil shale development. Although proceedings of each symposium were published, location of specific subject matter has been difficult due to lack of indexes and because titles were listed chronologically only in the table of contents of each proceedings. The results of the symposia, therefore, have not been used as beneficially as the value of the information warrants. This problem now has been eliminated by a comprehensive index that will permit easy access to the materials in the Oil Shale Symposia Proceedings. Dr. Gary Baughman and Christopher Cox have compiled an excellent index of all volumes of the Oil Shale Symposia Proceedings by subject, author, company, and chronological order of presentation, which makes access to the information quick, easy, and convenient. It is their plan to keep the index current by updating it from time to time. This accurate, readily accessible index will be a great convenience to all serious workers concerned with the development of an oil shale industry. We are indebted to them for this contribution--James H. Gary, Editor, Oil Shale Symposium Proceedings, September 24, 1982
STRUCTURAL GEOLOGY OF THE WOODFORD SHALE IN THE SOUTHEASTERN ANADARKO BASIN, GRADY COUNTY, OKLAHOMA
No full textThe Anadarko basin, especially the SCOOP (South Central Oklahoma Oil Play) and Merge areas, has become one of the most prospective and successful oil plays in the country. However, there is an increasing need to refine and improve the understanding of the general geological setting of the hydrocarbon producing formations within its boundaries, specifically the role of structure on accumulating and producing oil and gas.
The Devonian Woodford shale unconventional reservoir of the Anadarko basin is one of the main targets for exploration and production. It has been previously studied with a focus on its stratigraphy, geomechanics and geochemistry but not much about its structural geology. Most of the structural work done has been either at an outcrop level or at the state level.
This thesis uses well log analysis, 2-D seismic interpretation and well core observations to help define formation tops and construct cross sections and structural maps to provide a better developed structural framework for this productive area that comprises the northern limits of the SCOOP play and the transitional Merge play in Grady County, Oklahoma.
The resulting structural map for the Woodford shale features two structurally different regions. The first is a structurally stable region, with almost no faulting towards the central and northern part of the county and the second region, mainly in the southern half of the county is a more structurally complex region.
This work also combines this structural framework of the Woodford shale in the Grady County area with available production data to analyze and suggest that the gas production follows closely the structural setting of producing wells; increasing in the structurally stable zone and decreasing in areas with a higher number of faults. Oil production does not appear to be related to fault
Proceedings of the eighth oil shale symposium
No full textQuarterly of the Colorado School of Mines, v.70 no.3.8th Oil Shale Symposium.Includes illustrations, charts, graphs, tables.From the foreword: After over 50 years of predictions that shale oil production in the United States is on the threshold of commercial development, there is still no commercial size plant scheduled for construction. In 1920, technical problems were the main roadblock to commercialization of shale oil production, while today the major obstacles also include environmental and political problems as well as the lack of necessary economic incentives. In spite of the importance of environmental impact with respect to shale oil development, it was a deliberate decision not to include papers on environment in the program of the Eighth Oil Shale Symposium. This decision was made for two reasons: (1) the Seventh Oil Shale Symposium had dealt heavily with environmental and land-use planning, and (2) a survey of companies involved with field work in environmental aspects of oil shale development indicated more complete and definitive papers would be available in the fall of 1975 after another spring and summer of data collection. As a result the decision was made to limit the April meeting to papers that dealt with areas of shale oil production other than environmental and to schedule a special symposium on October 9th and 10th, 1975, restricted to "Environmental Aspects of Oil Shale Development." The need for efficient use and conservation of our energy resources is apparent to everyone today. In the past little attention was paid to energy efficiency of various sources of energy supply and no general ground rules were developed so that true comparisons could be made among energy sources. The keynote session of the Eighth Oil Shale Symposium was devoted to reporting "Input-Output Energy Studies for Development of Oil Shale Resources" and guideline discussions were encouraged. This provided a series of papers on net energy relationships as well as the limitations and restrictions of each of the studies. Hopefully this has given a better insight into the items that should be considered in all net energy studies and their relative importance. Efficient use of other minerals found in oil shale deposits is also a necessary restriction on development of energy sources from oil shale. If properly handled, the recovery of these minerals can help defray part of the costs of mining and land reclamation as well as provide minerals needed for this country's economic progress. Papers are included that pertain to other minerals found with oil shale as well as improvements in technology that will serve to make shale oil production more efficient and less costly. The success of the symposium is due largely to the interest and dedication of the authors of the papers and the support of their employers which permits and encourages them to make the results public. Appreciation is expressed to everyone participating, either as author, speaker or sponsoring company, who made this symposium possible. Special thanks are given to Jon Raese and the reviewer, Mark T. Atwood, who provided prompt and efficient publication of the proceedings. James H. Gary Vice President for Academic Affairs Colorado School of Mine
Water imbibition of shale and its potential influence on shale gas recovery-a comparative study of marine and continental shale formations
No full textA large volume of fracturing fluid is pumped into a well to stimulate shale formation. The water is imbibed into the reservoir during this procedure. The effect of the imbibed water on gas recovery is still in debate. In this work, we study the spontaneous imbibition of water into marine shale samples from the Sichuan Basin and continental shale samples from Erdos Basin to explore the fluid imbibition characteristics and permeability change during water imbibition. Comparison of imbibition experiments shows that shale has stronger water imbibition and diffusion capacity than relatively higher permeability sandstone. Once the imbibition stops, water in shale has stronger ability to diffuse into deeper matrix, the water content in the main flow path decreases. Experiments in this study show that marine shale has stronger water imbibition capacity than continental shale. The permeability of continental shale decreases significantly with increasing imbibition water volume; however, the permeability of marine shale decreases at first and increases after a certain imbibition time. The induced fracture is obvious in the marine shale. SEM analysis shows that the relationship between the clay mineral and organic matter of continental shale is much more complex than that of marine shale, which may be the key factor restricting the water imbibition because the flow path is trapped by swelled clay minerals. Through this study, we concluded that whether gas recovery benefits from water imbibition depends on three aspects: 1) the diffusion ability of liquid into matrix; 2) the new cracks introduced by imbibed water; and 3) the formation sensibility. This study is useful for optimizing fracture fluids and determining the best flow-back method. (C) 2016 Elsevier B.V. All rights reserved
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Comparative study for the interpretation of mineral concentrations, total porosity, and TOC in hydrocarbon-bearing shale from conventional well logs
No full texttextThe estimation of porosity, water saturation, kerogen concentration, and mineral composition is an integral part of unconventional shale reservoir formation evaluation. Porosity, water saturation, and kerogen content determine the amount of hydrocarbon-in-place while mineral composition affects hydro-fracture generation and propagation. Effective hydraulic fracturing is a basic requirement for economically viable flow of gas in very-low permeability shales. Brittle shales are favorable for initiation and propagation of hydraulic fracture because they require marginal or no plastic deformation. By contrast, ductile shales tend to oppose fracture propagation and can heal hydraulic fractures. Silica and carbonate-rich shales often exhibit brittle behavior while clay-rich shales tend to be ductile.
Many operating companies have turned their attention to neutron capture gamma-ray spectroscopy (NCS) logs for assessing in-situ mineral composition. The NCS tool converts the energy spectrum of neutron-induced captured gamma-rays into relative elemental yields and subsequently transforms them to dry-weight elemental fractions. However, NCS logs are not usually included in a well-logging suite due to cost, tool availability, and borehole conditions. Conventional well logs are typically acquired as a minimum logging program because they provide geologists and petrophysicists with the basic elements for tops identification, stratigraphic correlation, and net-pay determination. Most petrophysical interpretation techniques commonly used to quantify mineral composition from conventional well logs are based on the assumption that lithology is dominated by one or two minerals. In organic shale formations, these techniques are ineffective because all well logs are affected by large variations of mineralogy and pore structure. Even though it is difficult to separate the contribution from each mineral and fluid component on well logs using conventional interpretation methods, well logs still bear essential petrophysical properties that can be estimated using an inversion method.
This thesis introduces an inversion-based workflow to estimate mineral and fluid concentrations of shale gas formations using conventional well logs. The workflow starts with the construction and calibration of a mineral model based on core analysis of crushed samples and X-Ray Diffraction (XRD). We implement a mineral grouping approach that reduces the number of unknowns to be estimated by the inversion without loss of accuracy in the representation of the main minerals. The second step examines various methods that can provide good initial values for the inversion. For example, a reliable prediction of kerogen concentration can be obtained using the ΔlogR method (Passey et al., 1990) as well as an empirical correlation with gamma-ray or uranium logs. After the mineral model is constructed and a set of initial values are established, nonlinear joint inversion estimates mineral and fluid concentrations from conventional well logs. An iterative refinement of the mineral model can be necessary depending on formation complexity and data quality. The final step of the workflow is to perform rock classification to identify favorable production zones. These zones are selected based on their hydrocarbon potential inferred from inverted petrophysical properties.
Two synthetic examples with known mineral compositions and petrophysical properties are described to illustrate the application of inversion. The impact of shoulder-bed effects on inverted properties is examined for the two inversion modes: depth-by-depth and layer-by-layer. This thesis also documents several case studies from Haynesville and Barnett shales where the proposed workflow was successfully implemented and is in good agreement with core measurements and NCS logs. The field examples confirm the accuracy and reliability of nonlinear inversion to estimate porosity, water saturation, kerogen concentration, and mineral composition.Petroleum and Geosystems Engineerin
OIL POTENTIAL OF THE ASQUITH MARKER, LEWIS SHALE, GREATER GREEN RIVER BASIN, WYOMING.
No full textLarge volumes of gas and some oil have been produced from the Cretaceous Lewis Shale, and it is often considered a regional source of gas in the Greater Green River Basin. However, the Lewis Shale has never been studied as a potential oil-prone source or reservoir rock despite the fact that there is a small Lewis oil field on the western part of the Wamsutter arch: the Stage Stop field.
In this thesis, I evaluated the potential of the Asquith Marker as an oil-prone source rock. The Asquith Marker, in the lower Lewis Shale, is a relatively organic-rich shale easily recognizable on the gamma ray log as an anomalously high API. It is a third order condensed section that has a maximum thickness of 100ft. and covers a large area of the Greater Green River Basin.
Based upon limited subsurface data, I have evaluated samples from one cored well that penetrated the Asquith as well as samples from six other Lewis Shale cores above the Asquith Marker, five well cuttings and eight outcrop samples from the As-quith Marker. Structure and stratigraphic maps have been compiled and used to identi-fy the areas where the Asquith Marker is thickest and deep enough to generate oil. Analyses included Rock-Eval, XRD, vitrinite reflectance, and biomarker geochemis-try, from which the composition, maturity, oil potential and kerogen type were deter-mined.
Rock-Eval analysis showed some pitfalls associated with sample type (cutting and outcrop sample vs. core sample). Core samples showed high potential to generate oil from Type II kerogen. Lower TOC from cutting and outcrop samples was caused by caving, weathering and handling of the samples during the storage of the cutting samples. This low TOC also affected the parameters obtained from the Rock-Eval as HI, Tmax, OI and the S1, S2, S3 and S4 peaks from the pyrograms. Vitrinite reflec-tance from other intervals close to the Asquith Marker suggested the Asquith Marker interval is within the oil window or early oil window. Biomarker analysis was per-formed on three samples: one sample from the Amoco Champlin 276 D-1 well, one sample from the Amoco Champlin E- 1 well and one sample from Stage Stop Unit 2 well. This analysis suggested the samples are within the oil window or early oil win-dow from marine, hypersaline stratified waters with high clay content. There was also evidence of some higher plant material input.
The general sparseness of data has hindered a more robust analysis, but several indicators suggest the Asquith Marker might be oil-prone as an unconventional re-source shale. In order to define potential areas for unconventional development thick-ness, depth, vitrinite reflectance and biomarker maturity data were used as constraint. According to Jarvie (2005), the lower the TOC the thicker the shale interval must be in order to be economically viable for extraction. Depth was chosen based upon maturity and potential to generate hydrocarbons from TOC, biomarkers and vitrinite re-flectance. A depth between 1400-(-6600) ft. depth (TVDSS) was used as constraint. The total area obtained from these constraints is close to 2.5*107 acres; a map shows the aerial extent of the oil-prone Asquith Marker.
New information about two oil producing wells that were drilled as horizontal wells through the Asquith Marker (Rush Unit 4-1 and Spirit of Ratio 7-1H) is used as proof of concept. They have a total oil production of 26775 Bbls. and 14350 Bbls. respectively but the decline rate characteristics of unconventional wells led to the abandonment of the Rush Unit 4-1H well on 2016
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