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Abstract Najmah-Sargelu Formations of Kuwait show considerable potential as a new unconventional hydrocarbon play and produces mainly from fractures. The key uncertainties which affect the productivity are the nature and distribution of permeable fracture networks, and the limits of oil accumulation. This paper presents the results from whole-rock elemental analysis of three cored wells in UG field. The main objectives of this study are to use high-resolution elemental chemostratigraphy to gain a better understanding of the detailed stratigraphy and correlation of the Najmah-Sargelu Formations, to assess the chemo-sedimentology for determining the intervals of high organic content, to estimate the mineralogy of the sequence using an algorithm developed for an analog formation in North America; and to determine the most likely intervals to contain fractures, using a brittleness algorithm. A clear chemo stratigraphic zonation is recognized within the Najmah-Sargelu Formation. The larger divisions are driven mainly by inherent lithological variation. The finer divisions are delineated by more subtle chemo stratigraphic signals (K2O/Th and Rb/Al2O3 ratios) and preservation of organic matter (high V, Ni, Mo, and U abundances). Zones of alternating brittleness and ductility are clearly identified within the interbedded limestones and marlstones of Najmah-Sargelu Formation. Two unexpected but important features of the Najmah-Sargelu limestones were elucidated by the elemental data. Brittle, high-silica spiculites, with virtually no clay or silt, are more common than previously recognized from petrophysical logs and core descriptions in the upper Najmah limestones. In addition, the limestones adjacent to the spiculites tend to contain bitumen as pore-filling are recognized by the trace metal proxies. Ternary plots of V, Ni, and Mo differentiate the combinations of kerogen and bitumen present in the Najmah-Sargelu Formations. The clarity and sensitivity of the chemostratigraphic signals are sufficient to enhance formation evaluation, and can also assist borehole positioning using the RockWise ED-XRF instrument at wellsite.
- North America (1.00)
- Asia > Middle East > Saudi Arabia > Saudi Arabia - Kuwait Neutral Zone ("Partitioned Zone") (0.41)
- Asia > Middle East > Kuwait > Ahmadi Governorate (0.41)
- Geology > Geological Subdiscipline > Stratigraphy > Chemostratigraphy (0.91)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Limestone (0.89)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.72)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)
- (8 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Geologic modeling (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (0.91)
- Reservoir Description and Dynamics > Reservoir Characterization > Sedimentology (0.87)
Technology Update A two-step analysis can provide the key information needed to design optimal shale completions. The first step is to evaluate reservoir quality, which describes the hydrocarbon potential of a shale. The second step is to evaluate completion quality, which describes stimulation potential. Core analysis provides the basis to help calibrate the results of these two steps. The intersection of good reservoir quality and good completion quality leads to the best chance for success in shale completion. However, a failure to address both reservoir quality and completion quality will jeopardize the achievement of the ultimate goal: optimized production. A shale reservoir by definition is a hydrocarbon source, reservoir, trap, and seal in a single package. Though similar in outward appearance, no two shales are alike. They are typically complex, heterogeneous rocks with extremely low permeability. Stress anisotropy is commonplace. This calls for the judicious integration of geology, petrophysics, geomechanics, and reservoir engineering to solve the puzzle that will enable the reservoir to yield its prize. Reservoir Quality To determine reservoir quality, defined as the hydrocarbon potential of a shale, it is necessary to quantify the amount of hydrocarbon in place and its deliverability to the fracture face. To do this, we must know the organic matter content and type, its thermal maturity, the effective porosity, fluid saturations, matrix permeability, and reservoir pressure. The hydrocarbon in shale has evolved from thermogenic or biogenic alteration of kerogen, a fossilized organic material that is the source of oil and gas. In addition to providing the hydrocarbon source, kerogen plays a key role in developing reservoir quality in shales. Its degeneration creates pore space that makes up in part for the porosity lost during sedimentary compaction. Because of its extremely high surface area and affinity for hydrocarbon molecules, this pore space is an excellent storage medium for gas, which becomes adsorbed onto the organic surfaces. In addition, free gas or oil may exist in larger pores, both within kerogen and between mineral grains. Understanding the mix between adsorbed and free hydrocarbons is essential for calculating total hydrocarbon content. Because of the role of kerogen in creating pore space and providing hydrocarbon storage, there is a strong correlation between kerogen content and total porosity, hydrocarbon saturation, and permeability. Therefore, kerogen content, or total organic carbon content (TOC), is an important indicator of overall reservoir quality.
Abstract During the past six years, the technology for shale gas/oil developments in North America has seen many improvements and optimizations as the industry experiences a sharp rise in the contribution of hydrocarbons from these resources. More recently, Europe and Australia have joined the US in expanding recoverable hydrocarbons from these unconventional resources, and initial activities are on the rise in Latin America, China, Saudi Arabia and India. Despite such improvements and optimizations, a closer look at the performance reveals that not all wells are producing commercially. In addition, the hydraulic fracture stages are not all contributing within the producing wells. This scenario potentially suggests that it is important to target the field's sweet spots while dealing with shale resources (like most other hydrocarbon-bearing formations). Hence, resource development based on the current concepts of geometric placement of hydraulic fracture stages (e.g., using fixed well/fracture spacing) may not be appropriate to develop such heterogeneous unconventional resource basins. In the discussion we illustrate certain well-defined criteria that can identify the sweet spot locations within a field/basin for the optimal well placement. We further document the vital formation/zone characteristics that define the locations for hydraulic fracture stages and thus move away from the arbitrary geometric placement. The paper will discuss the well-placement optimization process and identify the required combination of proposed special petrophysical, geochemical, and geomechanical investigations (wireline, Logging While Drilling and cores). The hydraulic fracture stage placement analysis as presented, shoulders on the need to understand the existing natural fracture system. This understanding is achieved through geophysical log measurements and comprehensive analysis of the hydraulic fracture development pattern, as well as interaction of hydraulic fractures at each stage with the natural fractures. A naturally fractured reservoir can be drained more efficiently if a complex fracture network can be created by the hydraulic fracture stimulation. This begins by drilling the well in the direction of minimum principle horizontal stress in the area. The paper concludes by presenting examples demonstrating the practical application of some of the specific aspects of the methodology discussed and with a number of specific conclusions. In summary, the three key points to Proper Placement of Wells and Hydraulic Fracture Stages, in order to maximize the net value of an operator's asset are: Begin With a Complete Understanding of the Reservoir Use a Multidiscipline and Integrated Approach Across Each Phase of the Life Cycle Effectively Use Modern Technology
- North America > United States > Texas (1.00)
- Asia > Middle East (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.96)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (0.94)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Passive Seismic Surveying > Microseismic Surveying (0.68)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)
- (10 more...)
Summary Rock brittleness plays a significant role in effective hydraulic fracturing for shale gas production, and is often related to mineralogy, mechanical properties, and microstructure features in shales. We construct a rock physics workflow to link elastic properties of shales to complex constituents and specific microstructure attributes. Multiple compositions and various pore geometries are considered using a self-consistent approximation (SCA) method. The laminated textures due to the preferred orientations of clay particles and possible laminated distribution of kerogen are considered using Backus averaging to model the anisotropy (transverse isotropy) of shales. Results based on the analysis of the rock physics templates reveal that the degree of clay lamination significantly affects Vp/Vs of shales, whereas it has little impact on acoustic impedance of shales along the vertical direction. An increasing degree of clay lamination will increase Vp/Vs, and therefore the Poissonโs ratio. With increasing porosity, the variation of mineralogy has less impact on acoustic impedance than on Vp/Vs, which illustrates that Vp/Vs is a better indicator for lithology detection. On the other hand, acoustic impedance is a more suitable parameter to discriminate porosity compared with Vp/Vs. Our rock physics model is calibrated on the well log data from the Barnett Shale and is used to find reasonable parameters to characterize the Barnett Shale. Based on the model, we generate rock physics templates for the interpretation and prediction of shale rock brittleness, mineral constituents, and porosity from elastic properties of shales. Seismic AVO analysis based on modeling data from the top and base of the Barnett Shale illustrates that AVO intercept and gradient have predictable trends according to the variation of brittleness index, mineralogy, and porosity, which means that we can predict variations of such factors in space from seismic responses.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- North America > United States > Texas > Haynesville Shale Formation (0.99)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > United States > Louisiana > Haynesville Shale Formation (0.99)
- North America > United States > Arkansas > Haynesville Shale Formation (0.99)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
Abstract The Eagle Ford Shale hydrocarbon-fluid properties depend on the source rock maturity and, within the formation, occur in varying degrees of gas, gas condensate, and oil. Using conventional logs and pyrolysis data, several log-core regressions, such as delta log R, density, and uranium, can be derived to predict total organic carbon (TOC). The TOC can be used in conjunction with geochemical elemental measurements for a more accurate assessment of the formation kerogen and mineralogy, as well as hydrocarbon volumes. Nuclear magnetic resonance (NMR) porosity measures an apparent total porosity in the organic shale plays, measuring only the fluids present and excludes the kerogen. The complex refractive index method (CRIM) in conjunction with the mineralogy log data can be used to compute accurate dielectric porosities, which exclude both kerogen and hydrocarbon. Integrating the core TOC, predicted TOC, mineral analysis, NMR, and dielectric information, a final verification of the kerogen volume, hydrocarbon content, and mineral analysis can be assessed. This paper will describe the integration of conventional logs, a geochemical log, an NMR log, and dielectric to predict TOC, kerogen volume, and hydrocarbon volume, as well as, total porosity and mineralogy. The data is compared to the actual core data from three Eagle Ford wells, and it will be shown how the proposed approach will eliminate some coring operations. Finally, it will be shown how these interpretation results can be rolled up to make decisions on where to drill the lateral.
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (1.00)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.73)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)
- (13 more...)
Abstract Accurate quantification of total organic carbon (TOC) is an important step in evaluating log data in organic-rich reservoirs. The literature describes many log-based approaches for predicting TOC that have been introduced over the years, including the use of uranium content or GR linear regression, bulk density, the DeltaLogR approach, neural network approach, and a response equation-based method using sonic, density, and resistivity logs. All of the approaches require core-to-log calibration for validation. Each of these techniques involves assumptions for them to be valid, and, in a given instance, it is possible some techniques will not produce reliable results. However, good log-based TOC quantifications can be achieved by taking the median average of TOC estimates from several indicators. Many shale reservoirs contain 10 wt% pyrite and total organic carbon (TOC), which translates to 7% pyrite and 20% kerogen by volume. High volumetric percentages of pyrite and kerogen significantly affect the rock grain density. In low-porosity shale reservoirs, each 0.02 g/cm error in grain density produces approximately 1 p.u. error in porosity. Pyrite is commonly present in organic-rich shale intervals of shale gas formations because of the reducing conditions that enhanced organic matter preservation, and it may play a role in decreased resistivity response if the volume is sufficient. Consequently, in shale reservoirs, any method of predicting TOC using resistivity logs, such as DeltaLogR, should also consider the presence of pyrite. Similarly, TOC predictions based on bulk-density logs may also be sensitive to elevated pyrite concentrations. The link between pyrite presence and the depositional environment for many organic-rich shale reservoirs suggests that pyrite and sulfur may be useful TOC indicators in some situations. This paper examines the possible application of pyrite and sulfur for predicting TOC in shale reservoirs, such as in the Haynesville shale reservoir, but results should be applicable to many other shale reservoirs. An interesting result is that, although it may be possible to calibrate a TOC-based pyrite indicator for individual wells, the calibration is not universally applicable.
- North America > United States > Texas (1.00)
- North America > United States > Louisiana (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Mineral > Sulfide > Iron Sulfide > Pyrite (1.00)
- Materials > Metals & Mining (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Texas > Haynesville Shale Formation (0.99)
- North America > United States > Louisiana > Haynesville Shale Formation (0.99)
- North America > United States > Louisiana > Haynesville Formation (0.99)
- North America > United States > Arkansas > Haynesville Shale Formation (0.99)
ABSTRACT: Tight unconventional reservoirs have become an increasingly common target for hydrocarbon production. Exploitation of these resources requires a comprehensive reservoir description and characterization program to estimate reserves, identify properties which control production and account for fracturability. Multiscale imaging studies from the whole core to the nanometer scale can aid in understanding the multiple contributions of heterogeneity, natural fracture density, pore types, pore throat connectivity, mineral and organic content to the petrophysical response and production characteristics. In this paper we present three examples of the application of multiscale imaging to challenging unconventional reservoirs; a deep clastic tight gas reservoir, a fractured basement reservoir and coal seam gas reservoir. All of these samples exhibit features at multiple scales which present major challenges to petrophysical evaluation. In all cases heterogeneity and geological rock typing is undertaken at the core scale. FIBSEM imaging can then used to reveal the nanoporous microstructure of the key intervals within the phases of the core material. Petrophysical properties (porosity, permeability, elastic moduli) can also be computed for each key phase and the data upscaled using standard techniques. The presented case histories demonstrate that multiscale imaging and modelling provides a quick complimentary method to characterize the distribution and nature of different pore types and matrix components to characterize the elastic and dynamic rock properties even on rock fragments that are not suitable for conventional core analysis. Moreover the results have the potential to enhance our understanding of petrophysical, fracturing and multiphase flow processes in challenging unconventional reservoirs with low porosities and permeabilities. INTRODUCTION In recent years significant progress has been made in the development of high resolution 3D tomographic imaging and registration techniques to directly image rock microstructures across a continuous range of length scales (from nm to cm scales).
- Geology > Mineral (1.00)
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.68)
- Geology > Rock Type > Sedimentary Rock > Organic-Rich Rock > Coal (0.35)
ABSTRACT: New field deployable analytical techniques for measuring hydrocarbon pyrolysis, organic carbon content, inorganic elemental analysis of rock and mineralogy, and mud gas are proving to be very useful when drilling and completing shale wells. Experience in different shale plays have shown that these techniques can be used to assist in predicting fluid type, delineating potential pay zones and compartmentalization for strategic placement of fracturing stages based on rock and chemical properties. A combination of techniques involves an instrument for mobile programmed pyrolysis (PPy) which uses drill cuttings to evaluate residual oil content in source rock (S1), remaining hydrocarbon generation potential (S2), thermal maturity (Tmax) and total organic carbon (TOC). A semi-permeable membrane probe extracts and analyzes real-time hydrocarbon (C1 โ C8, benzene, and toluene) and non-hydrocarbon gases (CO2, N2) dissolved in the drilling fluid. Drill cuttings are also collected and evaluated onsite using X-ray fluorescence (XRF) and X-ray diffraction (XRD), which provides an elemental breakdown of the composition of the rock and the mineralogy. The elements can be used to create a chemical Gamma ray log, estimate TOC and identify mineralogy and brittleness. In unconventional reservoirs, such information can aid in the delineation of pay zones and be used to design horizontal completion and stimulation programs. This data is calibrated and integrated with ground truth core measurements and wire line log data to provide more comprehensive formation evaluation while drilling. Logging horizontal wells using downhole tools involves considerable engineering challenges and costs. Rugged, portable, surface-based technologies deployed at wellsite offer a cost-effective and lower-risk alternative for reservoir characterization. The examples presented in this paper demonstrate how surface analytical instruments can provide real-time insights into stratigraphy and reservoir characteristics during drilling of horizontal wells, and how those insights can be used to improve completions and hydraulic fractures.
- Europe (1.00)
- South America (0.94)
- North America > United States > Texas (0.69)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (0.68)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.39)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.55)
- 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)
- (31 more...)
Abstract Faced with increasing field maturity and production decline from conventional gas reservoirs, oil companies are shifting their focus and pursuing new alternatives; one of them being the development of shale and gas plays. To be economically viable, these low-permeability formations require fracture stimulation. Interval selection within shale reservoirs for hydraulic fracturing or horizontal laterals are based on several variables: sufficient organic matter or total organic carbon (TOC) and favorable hydraulic fracturing stimulation. The presence and extent of the natural fracture system can also influence the performance of a shale reservoir; therefore, natural fractures should be characterized within the shale formation not only from wireline or LWD borehole images logs but also from cross-dipole deep shear wave imaging which can illuminate fractures up to 60 ft away that do not intersect the well. To assess these aspects, a mineralogical, structural, and geomechanical characterization of the shale formation should be conducted. The mineralogical characterization and TOC quantifications mainly rely on a pulsed neutron spectroscopy and nuclear magnetic resonance (NMR) logs. The processing of capture and inelastic gamma ray spectra obtained from the pulsed neutron tool quantifies the formation's basic elemental composition, including silicon, calcium, aluminum, iron, sulfur, magnesium, and carbon. Geomechanical characterization is based on acoustic and density log responses. Variation in the reservoir mineralogy and TOC content affect the rock mechanics properties. Stress vs. strain curves can be derived from a micro-mechanical model of the rock which enable correlations between dynamic (obtained from acoustic logs) and static elastic properties (obtained from triaxial compression testing on core samples). Additionally, the azimuthal and transverse shear wave anisotropies are processed from cross-dipole acoustic logs to characterize the vertical and horizontal rock stiffness. This anisotropic characterization of the rock enables the evaluation of the fracture gradient and stress contrast between the target formation and the overlying and underlying formations. The paper focuses on the interaction between mineralogy, organic content and geomechanical analyses in shale gas reservoir evaluation.
- North America > United States > Texas (1.00)
- Europe (1.00)
- Asia (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Borehole Seismic Surveying (0.67)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- (13 more...)
ABSTRACT Our objective is to unlock the wealth of information contained in drill cuttings in real-time for complementing petrophysical characterization while drilling. The approach is to integrate the direct measurement from drill cuttings with Logging While Drilling (LWD) data to sup-port drilling, geosteering and formation evaluation. Our objective is to unlock the wealth of information contained in drill cuttings in real-time for complementing petrophysical characterization while drilling. The approach is to integrate the direct measurement from drill cuttings with Logging While Drilling (LWD) data to sup-port drilling, geosteering and formation evaluation. A way to tackle the above challenge is to perform a geochemical elemental analysis, by means of Energy-Dispersive X-Ray Fluorescence (ED-XRF). A reliable, portable ED-XRF instrument, robust enough for rig site employment is routinely used for a wellsite chemostratigraphy service. The instrument produces accurate elemental data, which can, in addition to its chemostratigraphic applications, be used for mineral and lithology modeling. A methodology has been developed to convert the elemental analysis into a mineralogical composition of the rock sample that is comparable to measurements from full scale X-Ray Diffraction (XRD) laboratory equipment. An experimental setup was deployed to assess the ability of modeling mineralogy from geochemical analysis (wellsite ED-XRF) of a set of rock samples in a blind test (Marsala et al., 2011). The analytical results were compared to results obtained from the same samples through state-of-the-art laboratory ED-XRF and wave-length dispersive XRF (WD-XRF) instruments. The geochemical data from the wellsite and the two lab-based instruments show good agreement. Finally, the modeled mineral compositions from whole-rock geochemical data were compared with the mineralogy determined from XRD analysis and showed good agreement. Modeled mineralogy from whole-rock geochemical data has been utilized in a wide range of applications rang-ing from mineralogy and lithology, to "brittleness index" determination for frac design in shale gas reservoirs.
- Europe (1.00)
- North America > United States (0.94)
- Asia > Middle East > Saudi Arabia (0.71)
- Africa (0.69)
- Geology > Geological Subdiscipline > Mineralogy (1.00)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Geological Subdiscipline > Stratigraphy > Chemostratigraphy (0.93)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.50)
- Well Drilling > Drilling Measurement, Data Acquisition and Automation > Logging while drilling (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Geologic modeling (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- (2 more...)