This paper presents the successful integration of an advanced nuclear magnetic resonance (NMR) log, a source-less technology, with core data and other openhole logs to resolve the challenges of reservoir characterization (including identification of tar mat) and to place the wells in targeted reservoirs zones. This enabled subsequent inflow control devices (ICD) completion design for optimal production in these complex carbonate Jurassic reservoirs. A comprehensive suite of advanced logs, conventional logs and core data were used. The wireline suite covered conventional (resistivity-density-neutron-gamma ray-acoustic) and advanced (NMR-elemental spectroscopy-image) technologies in one of the pilot wells. In another calibration well, data gathering was achieved with wireline (resistivity-density-neutron-gamma ray) and LWD NMR to log the same reservoirs. Integration using these conventional logs, advanced logs and core data established the correlations to derive permeability in this complex carbonate Jurassic reservoirs. From these study wells, a correlation was established between the NMR porosity, density/neutron porosity and core porosity to enhance confidence on NMR-measured porosity. The NMR permeability index was calibrated using parameters that were developed by integrating NMR results with the core data. This permeability relationship (core and NMR) was applied in all lateral wells with LWD NMR results that targeted the same reservoirs in the field. For delineating the tar mat interval, a combination of NMR, density and resistivity measurements was used. The LWD NMR results provided real-time reservoir characterization with rock quality (porosity distribution, permeability) that helped in ICD completion design and enhanced well placement. This approach and technology also enabled substantial rig time savings and reduced HSE risks. This approach demonstrates strong benefits of data integration and proven LWD NMR source-less and lithology-independent technology, in addition to the resistivity and gamma ray, as the preferred solution for advanced reservoir characterization, ICD completion design, and enhanced well placement in complex carbonate reservoirs. The solution for reservoir characterization enabled confident decisions on ICD completion design and enhanced well placement by implementation of source-less technology, eliminating the risks of using radioactive source-based technology.

Understanding the hydraulic properties of reservoir rocks is crucial for estimating reserves or managing storage and production of a reservoir. In reservoirs containing complex carbonates, rock-typing methodologies that recognize multimodal porosity have been widely used. A new rock-typing workflow based upon Thomeer-buoyancy modelling is presented, with proven application in Middle Eastern carbonate reservoirs where multimodal porosity is observed. Porosity reflects the total pore volume of the rock, but fluid transport within the media rock unit is dominated by the fractional pore volume connected to the largest pore throat system. The mercury intrusion capillary pressure (MICP) experiment alone provides insight into the connected porosity and permeability volumes. In addition, the MICP experiment establishes the relationship between the vertical saturation profile of the wetting and non-wetting fluid phases. A workflow that captures the buoyancy of the fluids (saturation-height) alongside this pore volume complexity can then provide insight into the pore geometry, saturation distribution and permeability of the investigated reservoir volume. This workflow is distinctive because it integrates reservoir physics with new analytic approaches that include a routine conversion of properties from ambient to reservoir conditions, a fully automated Thomeer deconvolution of mercury injection experiments (THOPAL) and a Thomeer-buoyancy analytical solver for properties estimation in the log domain. The solutions provided comprise continuous magnitude and category estimations of 1) permeability at reservoir conditions and Thomeer coefficients (G,Pd and Bv), 2) statistical uncertainties of the previous, 3) continuous scalar results in the hydrocarbon column including reservoir capillary pressure, bulk volume oil and Sw as well as probabilistic pore geometry grouping. Two case studies are presented to demonstrate the application to wellbores within the investigated Middle Eastern carbonate reservoirs.

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.

This paper presents the successful use of LWD NMR and LWD resistivity image log technology to meet the challenge of placing wells in a thin reservoir with lateral facies variation without the use of radioactive sources and with simultaneous data acquisition to evaluate the wells and design their downhole inflow control devices (ICDs). A series of horizontal producer wells were planned in a thin reservoir with lateral facies variation. After drilling the wells they were completed with downhole ICDs. Optimum placement of the wells within the reservoir and data acquisition to evaluate the wells and design their completions was achieved without the use of radioactive sources, as these created an unacceptable drilling risk. Rapid and accurate processing of the data in real time and subsequent design of the ICDs was required to enable the completions to run in a timely fashion. The NMR permeability was normalized using the new calibration parameters that were developed by integrating NMR results with core data, and the same relationship has been tested in other lateral wells. Real-time NMR total porosity played a significant part in facilitating effective geosteering and well placement without the drilling risks associated with radioactive sources. In addition, the NMR provided a porosity distribution that was used to estimate a permeability index. This index was normalized using core permeability available from offset appraisal wells. The core and NMR log data in the offset wells were combined to derive the parameters for an NMR permeability relationship. The standard volumetric analysis results and the permeability index were used for identifying reservoir flow units using crossplots of normalized flow capacity versus normalized storage capacity (modified Lorenz Plots). These results were then used to develop the parameters for the ICD completions. High resolution LWD image log data was incorporated to select the best possible sections in the wells for isolation of the ICD segments. Following completion and stimulation, multiphase PLTs were run across the ICD compartments to evaluate the wells. These results were then compared against expectations and used in subsequent well completion designs. The results of the wells presented show that the chosen methodology enables the successful placement and completion of horizontal wells in this reservoir. Decisions about ICD completion design can be made in a timely fashion just after the drilling phase is complete, avoiding rig downtime. This approach has become the default procedure for the field and will be used for the bulk of the remaining producer wells in the reservoir.

This paper presents the successful implementation of logging-while-drilling (LWD) nuclear magnetic resonance (NMR) source-less and lithology-independent technology to place an extended horizontal drain in best porous zone of a challenging, highly heterogeneous thin layer of carbonate rocks. The technology enables this goal by providing advanced formation evaluation and characterization. The objective was to drill a 3000-ft horizontal drain, targeting two stepped down porous units with a net thickness ranging from 6 to 9 ft, a porosity of 3 to 20 %, and a permeability range of 4 to 20 mD. To compare NMR porosity measurement and derived density/neutron porosity in a reference well, a combined bottom hole assembly was designed with density-neutron and NMR along with resistivity and gamma ray instruments to simultaneously log the reservoir. The NMR permeability index was calibrated using parameters developed by integrating the LWD-NMR results with core/mobility data. The generated relationship was then applied to calculate rock properties in wells with LWD-NMR, targeting the same reservoir in this field. The LWD-NMR porosity played an important role in real-time confirmation of well placement within the best porous zones. In addition, the instruments performed reservoir characterization such as porosity distribution (total, movable and bound) and permeability index derivation along the horizontal drain. The LWD-NMR results, porosity and calibrated permeability were used to identify reservoir flow units by applying a Modified Lorenz Plot, which resulted in identifying best producible flow units zones for well completion. Based on a consistent correlation between the neutron density-derived porosity and the NMR measured porosity achieved in the studied wells, NMR combined with resistivity and gamma-ray was a solution for geosteering. This combination also resulted in rig-time savings, and it eliminated risks associated with drilling using radioactive sources and formation evaluation rock properties in this reservoir. The replacement of radioactive source-based technology with the source-less LWD-NMR enabled efficient well placement and reservoir characterization for reservoir completion.