Reservoir Rock Typing and saturation modeling need a two-sided methodology. One side is the geological side of the rock types to populate properties within geological concepts. The other side is addressing reservoir flow and dynamic initialization with capillary pressure. The difficulty is to comply with both aspects especially in carbonates reservoirs with complex diagenesis and migration history. The objective of this paper is to describe the methodology and the results obtained in a complex carbonate reservoir. The approach is initiated from the sedimentological description from cores and complemented with microfacies from thin sections. The core-based rock types use the dominant rock fabrics, as well as the cementation and dissolution diagenetic processes. The groups are limited to similar pore throat size distribution and porosity-permeability relationships to stay compatible with property modeling at a later stage. At log-scale, the rock typing has a focus on the estimation of permeability using the most appropriate logs available in all wells. Those logs are porosity, mineral volumes, normalized saturation in invaded zone (Sxo), macro-porosity from borehole image or Nuclear Magnetic Resonance (NMR), NMR T2 log mean relaxation, and rigidity from sonic logs. A specific calculation to identify the presence of tar is also included to assess the permeability better and further interpret the saturation history. The MICP data defined the saturation height functions, according to the modality of the pore throat size. The log derived saturation, and the SHFs are used to identify Free Water Level (FWL) positions and interpret the migration history. The rock typing classification is well connected with the geological aspects of the reservoirs since it originates from the sedimentological description and the diagenetic processes. We identified a total of 21 rock types across all the formations of interest. We associated rock types with depositional environments ranging from supra-tidal to open marine that controls both the original rock fabrics and the diagenetic processes. The rock typing classification is also appropriate to model permeability and saturation since core petrophysical measurements were in use during the classification. The permeability estimation from logs uses multivariate regressions that have proven to be sensitive to permeability after a Principal Component Analysis per zones and per lithologies. The difference between the core permeability and the permeability derived from logs stays within one-fold of standard deviation as compared to the initial 3-fold range of porosity-permeability. We assigned the rock types with three Saturation Height Function (SHF) classes; (unimodal-dolomite, unimodal- limestone & Multimodal-Limestone). The log derived water saturation (Sw) from logs and SHF shows acceptable agreement. The reservoir rock typing and saturation modeling methodology described in this paper are considerate of honoring geological features and petrophysical properties to solve for complex diagenesis and post-migration fluid alteration and movement processes.
A comprehensive diagnostic data-fracturing campaign (Fracture Pressure Analysis: FPA) was undertaken by the Gas Fields Development Group (GFDG) of North Kuwait in January-March 2013. The campaign involved executing FPAs on the primary zone of interest (Organic-rich Carbonaceous Shale: OCS) as well as underlying and overlying carbonates to establish "fraccability" and in particular the hydraulic frac vertical containment aspect, which are much needed for the successful planning of an appraisal program. This paper summarizes the resuts of those FPA tests and how the acquired data is used to calibrate the wellbore geomechanical model. This initial FPA campaign is the onset of a more comprehensive evaluation program planned for 2013 onwards. FPA sequences were executed on the OCS, underlying and overlying formations with encouraging results. The main concern was whether the OCS would yield hydraulic fracture (fracture initiation) below surface treatment pressure limitation of 13,500 psi (Maximum allowable surface pressure). The fracture initiation was successfully established in all three zones. In addition, multiple "fracture re-opening tests" were performed to evaluate the ranges of the fracture closure stresses during the leak-off. Multiple down-hole memory gauges were utilized to ensure elimination of wellbore effects on treatment pressure. KCl-laden incompressible water-based fluid system enhanced with friction reducer was utilized in all three stages to ensure minimal friction loss and damage. This formation suite has very complex mineralogical attributes as it is a mixture of clastics, carbonates and hydrocarbons, with reservoirs that can be very tight (possibly at micro-Darcy). This campaign will lead to an optimal selection among the vertical completion options (hydro-fracturing design), and will help to successfully plan for horizontal well completions.
A North Oman Field producing from two stacked Cretaceous reservoirs characterized by variation in inter-particle porosity along with variable vuggular and fractured secondary porosity system was studied. The objective was to build a reliable DPDP reservoir static model with scarcely available key data. An interdisciplinary approach utilizing available data, supplemented with analogs was used to implement a hierarchically linked reservoir characterization and modeling workflow for the purpose dynamic flow simulation studies. In the absence of core data, the NMR T2 distribution and derived permeability scaled to well tests mobility were correlated with borehole image features in a key well to define a rock typing scheme. The saturation height function was developed directly from the Sw and resistivity logs, by transforming and adjusting NMR T2 distribution to saturation height. In wells with only conventional logs, the SHF was used to back-calculate permeability within the transition zone. Electrical image logs in horizontal wells were used to build a high-resolution layering framework extrapolated inter wells to model highly conductive features (vugs and fractures). To address a relationship between secondary porosity selectively seen in thin dense layers, a BHI-based layering along horizontal wells was used to build the reservoir stratigraphic correlation to capture vertical flow barriers and high permeability vuggy layers. This approach used textural characteristics of rocks together with production data to capture mechanical stratigraphic boundaries and enabled fracture density estimation per mechanical layer. Use of hierarchical modeling workflow enabled the use of available BHI based rock texture, VCL from computed logs and acoustic impedance from inverted 3D seismic data to build 3D probability cubes of "mud-supported" and "grain-supported" rock textures. Conditioned to those 3D textural trend models, some seismic attributes were used as a guide to stochastically model the distribution of rock fabric based on the Lucia classification and the related inter-granular porosity. Subsequently the 3D distribution of Lucia-based Permeability and SW properties were also developed. Based on the assumption that fractures are developed within the perturbed stress field caused by the activity of the main pre-existing faults, a geomechanically-based process NFP workflow enabled us to build reservoir-scale fracture models. This workflow integrated seismic scale faults, and the distribution of fracture geometry and density from the wells coming from BHI logs, together with seismic discontinuity planes extracted from frequency-based filtering of seismic structural attributes. The tectonic model boundary conditions were estimated using 1D geomechanical models and analog data from neighboring fields. NFP-workflow generated fracture drivers; together with other fracture parameters, estimated from analog fields, neighboring outcrops and open literature, which were used to build a 3D multi-scale hybrid fracture model of the reservoir. The DPDP static reservoir model allowed dynamic history matching of the field with only global parameter adjustments, thus validating the property distribution from this static model.
An advanced neutron spectroscopy measurement combining capture and inelastic spectroscopy with state-of-the-art hardware has been used to directly determine total organic content (TOC) and to provide detailed mineralogy characterization in an organic-rich source rock in Kuwait. The advanced spectroscopy measurement provides a direct measurement of TOC, obtained from the difference between the measured total carbon and the inorganic carbon obtained from the rock mineralogy. TOC is an important component of the evaluation of an unconventional reservoir as it is a direct input into the determination of the adsorbed gas volume. Core studies including X-ray fluorescence, dual-range infrared Fourier transform mineralogy evaluation, and coulometry for carbon were conducted to validate the measurement. The log spectroscopy results were compared with core TOC data and to core elemental and mineralogical data. Evaluation of the advanced spectroscopy tool was conducted in parallel with the previous-generation spectroscopy measurement to compare the results. The core TOC and the direct TOC log measurements of the advanced spectroscopy tool compared well. The core-to-log elemental dry weights comparison highlighted that, compared to the previous technology, the advanced measurement provided a more accurate evaluation of several elements (including aluminum, potassium, and magnesium). The core-to-log comparison also demonstrated that the new measurement provided robust answers in a tough logging environment, with an effective correction for the carbon content of oil-base mud and for barite, despite the high barite content in the mud. A particular finding of the chemistry/mineralogy combined core analysis was that a large quantity of sulfur, larger than is typically found in unconventional reservoirs, is associated with the kerogen. For the first time in Kuwait, the application of an advanced spectroscopy technology in a challenging carbonate environment effectively provides a detailed and accurate mineralogical description and a model-independent TOC measurement that were not previously available with conventional spectroscopy logging techniques.
Organic rich Kerogen layer of Lower Kimmeridgian to Upper Oxfordian age, deposited throughout Kuwait, is a TOC rich layer with varying TOC content between 2 to 20 wt% (in the vertical section) and having an average TOC of about 8 wt%. The depth of occurrence of this layer favorably places this zone to be having potential in rich gas condensate resource in the northern part of Kuwait. This layer occurs at a depth of 14000-16000 ft with a reservoir temperature of 270⁰-275⁰F, pressure of 11000 psi and average thickness of over 50ft. This is one of the main source rocks for majority of the oil and gas fields of Kuwait. This Kerogen section is penetrated through a number of vertical wells, as part of development of deeper reservoirs in this area, which offers an excellent opportunity to evaluate this section through core and open-hole log data. Because of the strong acoustic contrast with the overlying and underlying layers, this reservoir section is a very strong mappable seismic reflector.As part of appraising the potential of this layer, as a resource play, a comprehensive success criteria has been worked out for location selection. An integration of all available geo-scientific data such as geochemical, 3D seismic attributes, petrophysical analysis, borehole image interpretations, geo-mechanical, core and mud logs has been carried out. The above data integration/analysis was combined with the success criteria, leading to selection of sweet-spots for planning the first dedicated horizontal well targeted on this layer. This paper presents the success criteria worked out and the integration of data for high grading the localesweet-spots, for the first set of horizontal wells for appraising this deep HP-HT unconventional play of Kuwait.
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