Identifying oil-saturated versus water-saturated sands in shallow, unconsolidated, viscous-oil-bearing terrigenous-clastic reservoirs of Kuwait field is challenging. Field appraisal was based upon seismic, core and wireline-log data from 19 wells. Static and dynamic models incorporating all subsurface data were built to estimate oil-in-place and forecast production. Estimating and modeling fluid saturations in reservoir zones was accomplished by integrating core, dielectric-resistivity, Nuclear Magnetic Resonance (NMR) and Wireline Formation Tester (WFT) data. Wells were drilled along a northwest/southeast-trend, thus geologic and reservoir-property variability in east and west parts of the field are uncertain. Stratigraphy and lithologic properties in these Miocene-age fluvial to shallow-marine strata impart a complex 3–D fluid distribution in the field. Repeated shoreline progradations and retrogradations deposited a stratigraphic succession defined by five facies-associations (i.e., shoal, tidal flat, tidal channel, lagoon, sabkha). Five lithofacies (i.e., shale, shaly sandstone, sandstone, carbonate-cemented sandstone, evaporite) were identified from core, elemental spectroscopy logs, and X-ray diffraction (XRD) data. Facies associations and lithofacies models were built using a combination of multiple-point statistics and sequential-indicator simulation. Lithofacies distribution in the static model was constrained by the facies-association distribution; reservoir-property distribution (e.g., porosity, permeability) was conditioned by lithofacies. Discrete reservoir zones were defined to separate oil-saturated versus water-saturated sands. The volume and position of oil-bearing sands are controlled by the defined zones and permeability distribution. The oil-filling process in these viscous oil-bearing reservoirs is typically controlled by the pore throat distribution with the migrating oil taking the path of least resistance. Due to the presence of stratigraphic-flow baffles, fluid contacts vary from sand-to-sand vertically and laterally. Log data, core descriptions, ultraviolet photographs, WFT and pressure volume temperature (PVT) data guided the interpretation of lowest known oil and highest known water levels, thus reducing fluid saturation uncertainty in the field.
The Najmah Shale, an organic-rich marl, is generally considered the primary source rock for hydrocarbons in Kuwait’s Jurassic and Cretaceous reservoirs. The purpose of this study was to estimate the original hydrocarbons in place (OHIP) and the geomechanical properties of the Najmah reservoir to aid in the design of a hydraulic fracture stimulation program in West Kuwait. An integrated petrophysical evaluation utilized conventional and sidewall core measurements, and standard and advanced open-hole logs were used to estimate net pay, porosity, oil saturation, and geomechanical properties. Formation evaluation of the Najmah Shale as a potential unconventional reservoir posed numerous challenges. These challenges included the ambiguous effects that high total organic carbon (TOC) has on conventional porosity logs and resistivity logs and the associated shale volume estimations. In this study, a probabilistic multi-mineral model was developed to more accurately assess the TOC of the rock and the associated porosity, saturation, and clay volume. Advanced well logs, including spectral gamma ray and elemental spectroscopy logs, were used to improve the mineralogical model of the complex formation. Routine core analysis, programmed pyrolysis, and X-ray diffraction (XRD) analyses were used to verify and calibrate the multi-mineral model results. Since a dual-porosity system was present in the formation, the Simandoux saturation equation was used to evaluate the fluid saturations. Anisotropic horizontal stress profiles were developed for specific wells based on analysis of dipole sonic logs, resulting in a greater regional understanding of the target interval. Based on the results of the multi-mineral modeling, the average TOC of the Najmah Shale varies from well to well throughout West Kuwait, with values as high as 14.8%. The effective porosity of the Najmah Shale ranges from 1 to 8%. Water saturation is low for these organic-rich formations. Water zones may occur above or below the organic-rich interval depending on the location. The geomechanical properties of the Najmah Shale are conducive to hydraulic fracture stimulation, by analogy to proven productive shale plays. The Sargelu interval, below the Najmah Shale, exhibits distinctly higher minimum horizontal stress gradients while the limestone above the Najmah Shale presents a weaker stress barrier. The results of the probabilistic formation evaluation of the Najmah Shale indicated that a significant volume of hydrocarbons is present in the formation. The geomechanical properties of the Najmah and adjacent units are conducive to successful hydraulic fracture stimulation. The evaluation of water-bearing zones adjacent to the target formation is critical to the investigation of the formation’s stimulation potential.
For the Miocene Lower Fars reservoir in South Ratqa field of North Kuwait, a large investment has been made acquiring cores to accurately quantify rock properties. This paper will review the derivation of the five most commonly used methodologies for estimating volume of shale (Vsh) and clay volume (Vcl), discuss three iterations of Vsh and Vcl estimates for this reservoir, and show how core-derived Vsh and Vcl indicators were used to define three different cases for effective porosity (PHIE) in probabilistic volume estimation. Simplistic approaches for estimating Vsh and Vcl from gamma ray (GR) logs and confusion between what is Vcl and what is Vsh can lead to significant underestimation of PHIE and net sand. During a reservoir study of the Lower Fars heavy oil deposit, use was made of core visible shale descriptions, X-ray diffraction (XRD), petrography, scanning electron microscopy (SEM), and granulometric data to calibrate Vsh and Vcl estimates to rock-based ground truth data. As background to the study, the original documents proposing five commonly used shale volume relationships were reviewed. The linear gamma ray (GR) method was found to be based on the average chemical measurement of Thorium, Uranium and Potassium in 200 midcontinent United States shales. Synthetic rock was used to calibrate GR tools at an API test facility and linearity between the synthetic shale and zero point was assumed. Steiber (1970) and Clavier (1971) were numerical solutions tied to pulse neutron log interpretations. The two Larionov equations were based on granulometry data, described in a scan of the original Russian textbook (Larionov, 1969) found online. Core descriptions were available for 15 wells, XRD data were available for 52 wells, petrographic reports were available for 57 wells, and granulometric reports were available for 18 wells. Previous work on the field, which used a percentile-based GR Clavier(1971) solution for Vsh, was found to significantly overestimate Vsh. After core visual Vsh was described in six wells, a GR-based Vsh was estimated by rescaling the GR minimum and median to match core description Vsh. Clean intervals were matched this way, but this estimate was too optimistic in the shaley intervals. Functions of the density (RHOB) and neutron (NPHI) logs were used to identify shaley intervals and overrule the GR based interpretation. Several years passed and many more wells were drilled. After acquisition of XRD core Vcl data, Vcl was estimated from the thorium (THOR) log using the Larionov Young Rocks method and Vsh was estimated using the density/neutron crossplot method. In the cleanest sands, where core description and the density/neutron overlay indicated shale was absent, XRD indicated trace to minor levels of Vcl. The THOR log Vcl matched XRD total clay using the Larionov Young Rocks method in 26 out of 38 wells. The Clavier equation was too high for Vcl to match XRD data. Petrography and core description estimates of visible shale rarely saw any shale laminations or matrix beyond trace or minor amounts at depths where XRD sometimes showed 3 to 8 percent Vcl. SEM data showed ubiquitous but volumetrically insignificant clay grain coatings on quartz grains. The challenge was how to treat the small amounts of clay that were not part of the shale visible during the correction of density log total porosity (PHIT) to PHIE. Shale has significant porosity with capillary-bound water associated with non-clay shale-sized particles of quartz and other minerals, making Vcl the wrong choice for correcting PHIT to PHIE. Clay grain coats on quartz and a trace to minor proportion of lithic grains have much less capillary-bound water than laminated or structural shales. The PHIT to PHIE adjustment was varied by probability class. For P90, the standard PHIT to PHIE correction was performed over the full range of Vsh. For P50, at depths where Vsh was less than 0.1, no correction was made, PHIT was used as PHIE. For P10, PHIT was used as PHIE. A probabilistic approach to the PHIT to PHIE correction avoided a significant understatement in net pay and PHIE. The key was understanding the difference between clay and shale as applied to estimating PHIE from PHIT.
This paper summarizes a reservoir modeling study involving the evaluation of development strategies relevant to a newly discovered, unconsolidated sandstone heavy oil field in Kuwait. The methodologies used provided essential information to define and evaluate feasible options to develop the reservoir. A reservoir model was developed utilizing seismic, well-log, and core data. Petrophysical estimates of mineralogy, porosity, water saturation (Sw), and permeability were made and calibrated to core data. The field geology and the depositional analog guided the interpretations of the reservoir geomorphology and sediment-distribution patterns. Facies modeling was achieved through multiple-point statistics methodology. Porosity, permeability, and Sw were distributed using Sequential Gaussian Simulation. Various sensitivity runs were made for key parameters to understand the uncertainty of the model forecast. A full-field reservoir model (FFRM) was developed by incorporating available engineering analysis data. Development potential of the field through pressure depletion was studied through full-field reservoir simulations. Considering the high level of uncertainty of a new field, Low, Mid and High forecast cases were established for development through pressure depletion. Simulations of secondary and tertiary recovery techniques were then evaluated through sector model simulations and upscaled to field level. Finally, roadmaps were laid out for several development scenarios considered for the field. This paper demonstrates how various geological, petrophysical, and engineering data were used to build a representative full-field geocellular model (FFGM) and make field-performance forecasts under uncertainties pertaining to a green, heavy-oil field. During the model development stage, dielectric and elemental spectroscopy log data were utilized to enhance the petrophysical analyses. The distribution of Sw followed a distinct workflow where the distribution within each reservoir zone was based on several oil/water contacts (OWC). Available pressure-volume-temperature (PVT) analysis data were used to estimate and confirm the presence of water zones within the reservoir intervals.
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