Several challenges are associated with reservoir characterization of organic-rich, unconventional plays, most significantly with estimating producible hydrocarbons and identifying sweet spots for horizontal wells and subsequent stimulation. This paper illustrates the data integration approach from the Shilaif member and the important factors for the hydraulic fracturing simulations and execution. The Shilaif member consists of a succession of argillaceous limestone, mostly fine-grained packstones and wackestones with subordinate calcareous shales in the lower part. The complex carbonate lithology and fabric, combined with low porosity and the requirement to evaluate total organic carbon, presents a challenge to conventional logs and evaluation. Low permeability and productivity dictate the requirement to stimulate the wells effectively. Thorough integration of advanced and conventional log data (resistivity, neutron/density, dielectric, advanced acoustic, spectroscopy, nuclear magnetic resonance (NMR), and images) with core data and mud logs plays a critical role in the evaluation and development of these organic-rich reservoirs. Extensive data acquisition was planned with a wireline suite that included resistivity/density/neutron/spectral gamma ray; acoustic logs; acoustic image; NMR; advanced elemental spectroscopy; and dielectric technologies to characterize the hydrocarbon potential of organic-rich rock within the Shilaif member. The same suite of logs are critical for hydraulic fracturing simulations and play a heavy role when executing and pressure-matching the fracture geometry. Lithology and porosity from neutron/density logs are refined with NMR and spectroscopy to enable accurate evaluation of total organic carbon (TOC) and volumes. The advanced elemental spectroscopy data provided the mineralogy, the amount of carbon in the rock, and consequently the associated organic carbon within the Shilaif member. The NMR technology provided lithology-independent total porosity. The difference between the NMR and the density techniques provides accurate information about organic matter. NMR technology in this present case study was used to identify and differentiate the organic matter and hydrocarbon presence within the Shilaif member. Acoustic and image logs were used to evaluate the geomechanical properties that enable stimulation design to maximize the drainage while remaining within the boundaries of the reservoir. Accurate calibration of the stress profiles from core data assured the stimulation design was operationally achievable within pressure specifications and bounding formations. Detailed knowledge of natural fracture networks was critical to building an accurate geomechanical model. A complete workflow from formation evaluation to selection of interval to stimulate the Shilaif formation will be presented and used for future well development. The data integration work illustrated in the paper is a key for unconventional reservoir characterization that enabled identification of the sweet spots for horizontal wells and the successful hydraulic fracturing in the organic rich rocks of the Shilaif member.

Several challenges are associated with the characterization of organic rich unconventional plays, most significantly with the identification of sweet spots for optimum placement of horizontal wells, estimation of producible hydrocarbons and subsequent stimulation design. This paper presents the petrophysics and geomechanics integration approach from the X Formation and the important factors for the identification of sweet spots. The case study concentrates on the X Formation that consists of a succession of argillaceous limestone, mostly fine grained packstones and wackestones together with subordinate calcareous shales in the lower part. The complex carbonate lithology and fabric combined with low porosity and the requirement to evaluate total organic carbon presents a challenge to conventional logs and evaluation of them. Amid all the rock properties, the low permeability and productivity dictate the requirement to stimulate the wells effectively. Detailed integration of advanced and conventional log data, core data, mud logs and geomechanical analysis plays a critical role in the evaluation and development of these organic rich unconventional reservoirs. Extensive data gathering was done with wireline logging suite, which covered Resistivitiy/Density/Neutron/Spectral GR- Acoustic logs – Resistivity & Acoustic Images – Dielectric- NMR - Advanced Elemental Spectroscopy technologies and microfrac tests to characterize the hydrocarbon potential, sweet spots and in-situ stress contrast within the organic rich X Formation. The azimuthal and transverse acoustic anisotropies were obtained from X-dipole data to fully characterize the elastic properties of the formation. The static elastic properties were obtained using empirical core correlations as triaxial core tests were not available at the time of the study. The stress profile was calibrated against straddle packer microfrac tests to identify intervals with stress contrast for proper hydraulic fracturing interval selection. The integration of conventional and advanced logs enabled the accurate evaluation of total organic carbon (TOC), petrophysical volumes, and sweet spot selection. The advanced elemental spectroscopy data provided the mineralogy, amount of carbon presence in the rock, and consequently the associated organic carbon within the X Formation. The NMR reservoir characterization provided lithology independent total porosity. The difference between the NMR and density porosities provides additional information about organic matter. NMR data was utilized in this case study to identify and differentiate the organic matter and hydrocarbon presence within the X Formation. Acoustic and image logs provided the geomechanical properties that enable selection of the best intervals for microfrac stress measurement and proper fracture containment modeling. Geomechanical workflow allowed identification of intervals with a good stress contrast in X formation. The core data and stress measurements are recommended for the accurate calibration of the stress profiles and hydraulic fracture propagation modeling. The extensive data integration work presented in this single-well study within X Fomation, is a key factor for any organic rich unconventional reservoir characterization that integrated geology, petrophysics, mineralogy, and geomechanics for sweet spot identification within tight oil carbonate reservoirs.

Several challenges are associated with reservoir characterization of organic-rich, unconventional plays, most significantly with estimating producible hydrocarbons and identifying potential zones to land horizontal wells and subsequent stimulation. This paper illustrates integrated approach towards successful characterization of the Cretaceous carbonate major source rock-a lateral seal Shilaif formation in the recently developing area of syncline shape field in Onshore UAE. The Shilaif formation that was deposited under intra-shelf basinal conditions, contains sediments of argillaceous limestone, mostly fine-grained packstones and shaly lime mudstone-wackestones with subordinate calcareous shales in the lower part. Presence of bitumen and low permeability indicate the requirement to stimulate the wells effectively. Quantification of bitumen and light hydrocarbon through integration of advanced and conventional log data with core data and mud logs plays a critical role in the evaluation and development of these organic-rich reservoirs. Extensive data acquisition was planned with a wireline suite that included resistivity/density/neutron/spectral gamma ray; acoustic logs; resistivity image; nuclear magnetic resonance (NMR); advanced elemental spectroscopy; and dielectric technologies to characterize the hydrocarbon potential of organic-rich Shilaif unconventional play. NMR and Spectroscopy were used to refine lithology and porosity, which reduces the associated uncertinity in the evaluation of total organic carbon (TOC) and volumes. The advanced elemental spectroscopy data provided the mineralogy, the amount of carbon in the rock, and consequently the associated organic carbon within the Shilaif formation. The NMR technology provided lithology-independent total porosity and moveable versus non-moveable fluids quantification when integrated with density/neutron. NMR technology in this present case study was used to identify and differentiate the organic matter and hydrocarbon presence within the Shilaif formation. The water filled porosity and textural parameter from dielectric inversion results helped in more accurate water saturation estimation in the tight formation. Acoustic data results and high-resolution resistivity image logs were used to evaluate the geomechanical properties. In addition, Resistivity image data provided detailed knowledge of geological features, faults and natural fracture networks within the study zone to enable optimization of development scenario based on the reservoir properties. The data integration work illustrated in the paper is a key for unconventional reservoir characterization that enabled identification of the potential zone/zones of interests for horizontal wells and the successful development of the organic rich rocks of the Shilaif formation.

Several challenges are associated with the characterization of low permeability reservoirs, most significantly for the enhance oil recovery operations. The scope of this work presents the integration of petrophysics data and its application in selection of the Microfrac intervals to measure downhole fracture-initiation pressures in multiple carbonate reservoirs located onshore about 50 km from Abu Dhabi city. The objective of characterizing formation breakdown across several reservoirs is to quantify the maximum gas and CO2 injection capacity on each reservoir layer for pressure maintenance and enhance oil recovery operations. This study also acquires pore pressure and fracture closure pressure measurements for calibrating the geomechanical in-situ stress model and far-field lateral strain boundary conditions. The case study concentrates on the multiple carbonate reservoirs that consists of a succession of clean limestone and intermittent dolomitic limestone. The complex carbonate lithology and fabric combined with low permeability presents a challenge to conventional logs and evaluation. Detailed integration of advanced and conventional logs (resistivity, neutron/density, advanced acoustic logs, Dielectric, NMR, Borehole image), Pressure testing & Sampling, Microfrac in-situ stress measurements and analysis plays a critical role in characterizing the reservoir properties and enhance oil recovery operations. Extensive data gathering is conducted with wireline suite, which covered Advanced Straddle Packer/Pressure Test & Sampling - Resistivity/Density/Neutron/Spectral GR – Acoustic logs – Resistivity Image – NMR – Dielectric technologies for reservoir properties of multiple carbonate reservoirs. The advanced acoustic analysis is performed in order to study elastic properties of the formation along with identifying transverse and azimuthal anisotropic intervals. The Geomechanical modeling is performed and stress profile is calculated to identify intervals with a stress contrast, which is important for the following stress measurement interval selection. The Microfrac in-situ stress measurements provide critical subsurface information to accurately predict wellbore stability, hydraulic fracture containment and CO2 injection capacity for effective enhance oil recovery within these reservoirs. The conventional logs, advanced logs, and Microfrac in-situ measurements and analysis enabled reservoir characterization and development plans for enhance oil recovery operations. The NMR technology provided lithology independent total porosity, permeability estimations and reservoir rock quality. Advanced multifrequency Dielectric measurement provided the fluid saturation in the invaded zone and textural parameters. Advanced Acoustic and image logs provided the geomechanical properties that enable to choose the best intervals for the following Microfrac stress measurement. Geomechanical workflow allowed identifying stress measurement intervals with a good stress contrast in multiple carbonate reservoir intervals. The data integration work illustrated in the paper is a key for any reservoir characterization that enabled property evaluation and successful Microfrac stress measurement. These measurements provide critical subsurface information to accurately predict wellbore stability, hydraulic fracture containment and CO2 injection capacity for effective enhance oil recovery within these reservoirs. This in-situ stress wellbore data represents the first of its kind in the field allowing petroleum and reservoir engineers to optimize the subsurface injection plans for efficient field developing.

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