Gas shales are economically viable hydrocarbon prospects that have proven to be successful in North America. Unlike conventional hydrocarbon prospects, gas shales serve as the source, seal, and the reservoir rock. Generating commercial production from these unique lithofacies requires stimulation through extensive hydraulic fracturing. The absence of an accurate petrophysical model for these unconventional plays makes the prediction of economic productivity and fracturing success risky.This paper presents an integrated approach to petrophysical evaluation of shale gas reservoirs, specifically, the Barnett Shale from the Fort Worth basin is used as an example. The approach makes use of different formation evaluation data, including density, neutron, acoustic, nuclear magnetic resonance, and geochemical logging data. This combination of logging measurements is used to provide lithology, stratigraphy and mineralogy. It also differentiates source rock intervals, classifies depositional facies by their petrophysical and geomechanical properties, and quantifies total organic carbon. The analysis is also employed to locate optimal completion intervals, zones preferable for horizontal sections, and intervals of possible fracture propagation attenuation. Resistivity image analysis complements the approach with the identification of natural and drilling induced fractures. We compare results from three different wells to show the effectiveness of the method for shale gas characterization.The methodology presented provides a means to understand the geomechanical and petrophysical properties of the Barnett Shale. This knowledge can be used to design a selective completion strategy that has the potential to reduce fracturing expenses and optimize well productivity. Though developed specifically for the Barnett Shale, the underlying ideas are applicable to other thermogenic shale gas plays in North America.
The assessment of reservoir productivity and subsurface hydrocarbon can be significantly enhanced through an understanding of formation mineralogy and organic carbon. Such information allows petrophysicists to resolve ambiguities in their predictions of reservoir hydrocarbon potential. While core samples are a prime source for exact formation mineralogy, excellent results can also be derived in a timely and cost-efficient manner from in-situ log chemistry measurements of the rock. A direct measurement of the formation's elemental concentrations is achieved using a gamma ray scintillation sensor in combination with a 14-MeV pulsed-neutron generator. The most important element measured is carbon, as it may provide a direct indication of reservoir hydrocarbons. This paper presents a method for determining the amount of organic carbon in subsurface formations using a pulsed-neutron mineralogy tool and a natural gamma ray spectroscopy tool. The natural, inelastic, and capture gamma ray energy spectra from these instruments are used to extract the chemistry of the subsurface formation being investigated. The elemental concentrations measured include Al, C, Ca, Fe, Gd, K, Mg, S, Si, Th, Ti, and U. Carbon is very difficult to measure without the inelastic spectrum generated from a pulsed-neutron source. An interpretation process, based upon the geochemistry of petroleum-bearing formations, is employed to derive the lithology and mineralogy which leads to the interpretation of the carbon measurement. The oil saturation can be computed in conventional reservoirs, assuming that the amount of carbon in excess of that required for the inorganic matrix mineralogy is part of the pore fluid as hydrocarbon. The direct carbon measurement is also important in laminated shaly sands or in low-salinity reservoirs, where oil saturation determination from indirect measurements, such as resistivity, is not compatible with the environment. In other formations the carbon can be determined to be a component of the rock matrix as kerogen or coal, both of which are uniquely identified with this logging system. Kerogen becomes extremely important in the evaluation of shale gas formations. Field examples are presented to illustrate the effectiveness of the carbon measurement. Introduction Subsurface organic carbon, i.e., carbon that does not belong to any of the carbonate minerals, indicates the presence of oil, natural gas, coal, or kerogen. Although the amount of carbon is one of the most important quantities in formation evaluation, openhole tools often provide only indirect measurements of hydrocarbons. Traditional electrical tools, for example, measure oil saturation indirectly based upon a comparison of the resistivity of saline and non-saline formation fluids. This approach works best when the salinity of the formation water is high to moderate; if connate water salinity is low, resistivity methods cannot differentiate water from hydrocarbon.
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractFaced 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.
Several wells have been drilled and stimulated in a tight gas field in Middle East, however, very few have been economic. Many wells encountered difficulties pumping the required treatment and a number of horizontal wells did not produce as expected. A fit-for-purpose integrated subsurface model coupling geophysical, petrophysical, and geomechanical models with fully 3D hydraulic fracture simulation modeling was carried out to provide the operational path forward to overcome these challenges. This study is a showcase of the applicability of our integrated approach to simulate fluid flow and proppant placement within complex, naturally fractured reservoirs where the interaction between induced fractures and natural fractures dominates hydraulic fracture propagation [Izadi et al. 2015; Cruz et al. 2016; Izadi et al. 2017; Izadi et al. 2018; Cruz et al. 2018]. Seismic data calibrated with rock physics analyses were used to delineate structural components and incorporate rock properties into the high-fidelity 3D subsurface model. High porosity zones and areas of high natural fracture intensity were identified with seismic acoustic impedance and geometric attributes. Reservoir properties of porosity, permeability and gas saturations vary across this field. Variations in geomechanical parameters correlate spatially with variations in porosity and permeability. This paper demonstrates a methodology to evaluate reservoir heterogeneities on hydraulic fractures propagation through fully 3D simulations at a planned well's location.
I @ Copyrlsht 1977, Am.,kon Instltut. d Mining, Metalkqtlcel, ond Petrol.wn En~hreers, Inc. I I This paper was pre$ented at the 52nd Annual Fall Technical Conforonce and ExhlbNon af the society of Petroleum Engineers of AIME, huld in Darwur, Colorado, Oct. 9.12, 1977. The mot~rlcil Is sublect to carrectlon by the outhar, Permission to copy is restricted to an abstract of not more than 300 words. Write: 6200 N. Control Expy, Doilat, Texas 75206, ABSTRA%T Wgh.angle wells ate becoming com?itonplace, particularly in ofisbore areas. Because O!this, it A hecwne important to increase the deviation angles at which wells can be sotsvtwtiotsatl~logged. Moreover, /kt2 p~annitsg factors are needed to decide whether to try gravity-descent or pump-down tools as tbe first attempt at Iogging high-angle holes. This paper describes work which contributes sigtsificantlyto both objectives. New equipment has been introduced to reduce bole friction, i~crease tool weight and flexibility, atsd provide e surface indication of push or pttll forces at the too! bead. These devices have been extetssivelj /fieldtestedin wells with deviations ranging from !5 to its excess oj 70 degrees, in tbe Gulf of Mexico offshore area.hlaximum deviations successfully logged by use oj the new equipment vere somewhat less than the limits predicted b~theoretical and laboratory work, but there has beets a dramatic improvemetst in success ratios jor logging these high-angle wells.
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