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Abstract Recently, Saudi Aramco upstream activities in unconventional gas, and in particular tight gas sands, have been identified as a focus area. Integral to understanding the potential of tight gas as a resource, is an understanding of the petrophysical characterization of tight gas intervals. This paper presents a review of the petrophysical challenges in the evaluation of tight gas intervals encountered within an existing producing field producing from formation U. This formation can be highly variable and although it can be highly productive, in some areas the geology has produced poorer reservoir quality rock. Production from wells which penetrate these areas can exhibit "Tight Gas" characteristics. Core and log data from existing fields are abundant and cover both good and poorer quality reservoir intervals. The factors which impact the evaluation of these "Tight Gas" intervals, in this relatively well sampled environment, can be generalized to the evaluation of less well studied tight gas formations. The results of this review identify many areas where current techniques and tools fall short of providing an adequate characterization. In particular, the quantification of mineralogy and diagenesis is seen as important, as is the quantification of saturations and accurate measurement of micro-Darcy permeabilities. Areas where current techniques require improvement are highlighted and projects that are in progress to address these issues and improve the evaluation of tight gas are detailed. One area which is highlighted as holding potential is rock typing, which can categorize different types of tight gas interval based on clay content or mineralogy. Three wells have been selected for a fracturing exercise as a proof of concept to assess the production potential. The results of the fracturing exercise are presented relative to the petrophysical evaluation of these wells.
Abstract This paper presents a work-flow process to describe and characterize tight gas sands. The ultimate objective of this work-flow is to provide a consistent methodology to systematically integrate both large-scale geologic elements and small-scale rock petrology with the physical rock properties for low-permeability sandstone reservoirs. To that end, our work-flow integrates multiple data evaluation techniques and multiple data scales using a core-based rock typing approach that is designed to capture rock properties characteristic of tight gas sands. Fundamental to this process model are identification and comparison of three different rock types — depositional, petrographic, and hydraulic. These rock types are defined as:Depositional — These are rock types that are derived from core-based descriptions of genetic units which are defined as collections of rocks grouped according to similarities in composition, texture, sedimentary structure, and stratigraphic sequence as influenced by the depositional environment. These rock types represent original large-scale rock properties present at deposition. Petrographic — These are rock types which are also described within the context of the geological framework, but the rock type criteria are based on pore-scale, microscopic imaging of the current pore structure — as well as the rock texture and composition, clay mineralogy, and diagenesis. Hydraulic — These are rock types that are also defined at the pore scale, but in this case we define "hydraulic" rock types as those that quantify the physical flow and storage properties of the rock relative to the native fluid(s) — as controlled by the dimensions, geometry, and distribution of the current pore and pore throat structure. Each rock type represents different physical and chemical processes affecting rock properties during the depositional and paragenetic cycles. Since most tight gas sands have been subjected to post-depositional diagenesis, a comparison of all three rock types will allow us to assess the impact of diagenesis on rock properties. If diagenesis is minor, the depositional environment (and depositional rock types) as well as the expected rock properties derived from those depositional conditions will be good predictors of rock quality. However, if the reservoir rock has been subjected to significant diagenesis, the original rock properties present at deposition will be quite different than the current properties. More specifically, use of the depositional environment and the associated rock types (in isolation) to guide field development activities may result in ineffective exploitation. Introduction Unconventional natural gas resources — tight gas sands, naturally-fractured gas shales, and coalbed methane reservoirs — comprise a significant percentage of the North American natural gas resource base and these systems represent an important source for future reserve growth and production. Similar to conventional hydrocarbon systems, unconventional gas reservoirs are characterized by complex geological and petrophysical systems as well as heterogeneities — at all scales. However, unlike conventional reservoirs, unconventional gas reservoirs typically exhibit gas storage and flow characteristics which are uniquely tied to geology — deposition and diagenetic processes. As a result, effective resource exploitation requires a comprehensive reservoir description and characterization program to quantify gas-in-place and to identify those reservoir properties which control production. Although many unconventional natural gas resources are characterized by low permeabilities, this paper addresses only low-permeability sandstone reservoirs, i.e., tight gas sands.
Merletti, G. (BP) | Gramin, P. (BP) | Salunke, S. (BP) | Hamman, J. (BP) | Spain, D. (BP) | Shabro, V. (BP) | Armitage, P. (BP) | Torres-Verdin, C. (The University of Texas) | Salter, G. (Core Laboratories) | Dacy, J. (Core Laboratories)
Tight-gas reservoirs undergo unique and often complex burial, diagenetic, structural, fluid pressure and saturation histories. Porosity alteration from compaction, cementation and grain leaching can continue after hydrocarbon charge, further complicating saturation modelling. Many reservoirs have gone through multiple cycles of drainage and imbibition, often at different stages on the diagenetic pathway to current pore-scale morphologies. The understanding of saturation distribution and state is not only desired, but required for predicting reservoir performance, estimating realistic recoverable volumes, and optimizing costs for development and production.
Three depositional facies groups were interpreted in the Almond formation. The non-marine facies (fluvial and coastal plain) is a sublitharenite typically with 6-9% primary intergranular porosity, 3-5% secondary intragranular porosity and limited authigenic and carbonate cement (6-16%). The delta facies is a litharenite with 25-40% lithics, <4% primary intergranular and 5-10% secondary intragranular porosity and moderate authigenic and carbonate cement (7%). The shoreface is a litharenite with 16-24% lithics, 6% primary intergranular porosity and 3% intragranular secondary porosity and significant authigenic and carbonate cement (16%). These groups are commonly fine grained and well sorted. The differences in pore architecture arise from differences in primary depositional fabric and rock frame mineralogy and their subsequent diagenetic alteration; yielding predictive trends in porosity-permeability space.
Drainage and imbibition saturation-height models have been developed from core studies and integrated with logs to verify that reservoirs are at primary drainage and to highlight any potential imbibition due to trap tilting or leaking. Centrifuge and multi-cycle mercury injection data were integrated to produce composite drainage capillary pressure curves. A Thomeer saturation model was used to fit parameters such as entry pressure, geometric factor and irreducible water saturation to the capillary pressure tests. These parameters are commonly correlated to porosity and permeability through discrete petrophysical rock types. We found better correlations when parameters are correlated by depositional and diagenetic facies as a continuum across all rock qualities.
Stressed mercury extrusion tests are commonly used for modelling water saturation through the imbibition process. These tests display no correlation with rock quality at low capillary pressures. To circumvent these problems, mercury extrusion was integrated with maximum trapped gas measurements obtained by counter-current imbibition experiments. As trapped gas saturation showed a scattered distribution, data were investigated by aspect ratio estimates and secondary/total porosity ratio from thin-section petrography. In addition to the trapped gas saturation, geometrical factor and initial water saturations were used to fit a Brooks-Corey model.
Using the resistivity-derived water saturation model as reference, the free water level for drainage and imbibition models was optimized by matching saturation-height models in reservoirs free of resistivity shoulder bed effects. The accuracy of the match in different rock qualities provided insights on the likely saturation state of reservoirs. Such observations were used to develop successful interpretations of the special distribution of free-water level, reservoir architecture, and hydrocarbon charge.
Silva Gonzalez, Patricio (Stratum Reservoir) | Fernandes, Melissa (Stratum Reservoir) | Siddiqi, Saad (Stratum Reservoir) | Hannon, Loay (Stratum Reservoir) | Steiner, Stefan (ADNOC Upstream) | Chitrao, Amogh (ADNOC Upstream)
Abstract Rock typing represents an important tool for classifying clastic reservoir rocks, especially in reservoirs showing low permeability and low porosity values. For this study we first approach these challenges from a geological perspective and subsequently translate the results of traditional facies and RQ analysis into rock types by integrating previously obtained results with mercury injection capillary pressure (MICP) data. The rock typing workflow proposed by Rushing et al. (2008) is applied to the low porosity-low permeability Unayzah Formation penetrated in three offshore wells, UAE. The characterisation of this type of low reservoir quality (RQ) rock confronts the geologist with some challenges. The Unayzah Formation is an important clastic reservoir unit in the Middle East, especially in the UAE. It is characterized by low porosity and low permeability values and therefore, according to Holditch (2006) can be classified as a tight gas reservoir where a tight gas reservoir is "a reservoir that cannot be produced at economic flow rates nor recover economic volumes of natural gas unless the well is stimulated by a large hydraulic fracture treatment or produced by use of a horizontal wellbore or multilateral wellbores". In order to characterize the Unayzah Formation we used newly acquired geological and laboratory data obtained from detailed core description, facies, petrographic- and reservoir quality analysis. In a second step we translated these geological laboratory related data into rock types by integrating these data with MICP data considering pore throat geometries for a more accurate reservoir quality characterisation of the Unayzah Formation.
Abstract A translation scheme must be established to link core properties, such as rock type and permeability, from core intervals to non-cored intervals. Such a translation determines accurate and consistent permeability predictions across the field. This study focuses on an Early - Middle Devonian sand-dominated, tidal-estuarine depositional sequence. The formation is characterized by permeability variations caused by rapid facies changes, modified by a highly variable diagenetic overprint. Reservoir production is characterized by relatively thin limited intervals with prolific flow; and other intervals where the flow is low, despite permeability data, which suggest better productivity. These properties reflect a high uncertainty scatter in the permeability distribution. Existing permeability modeling techniques often fail to capture the actual range and scatter of permeability present in the formation: At the low porosity range the modeled permeability overestimates the potential flow and underestimates the performance of the prolific intervals. This paper presents an approach to improve the permeability prediction by reducing the permeability uncertainty scatter using electrofacies groupings; then, by including the remaining permeability uncertainty scatter in the modeled result. Furthermore, recently acquired and more accurate core permeability measurements at the micro-Darcy range have improved the definition of the low permeability range for this reservoir through the higher resolution measurement. The results of this work were an improvement in the permeability predictive model. In particular, the calibration of the low permeability intervals was better defined through an improved stress correction. At the high permeability end the identification of productive intervals was improved by the reservoir quality clustering approach combined with the core permeability statistics. This approach results in improved reservoir characterization with better predictive capacity through better modeling of the dynamic permeability range.