High gas flow rates in deep-buried dolomitized reservoir from an offshore field Abu Dhabi cannot be explained by the low matrix permeability. Previous permeability multiplier based on distance to major faults is not a solid geological solution due to over-simplifying reservoir geomechanics, overlooking folding-related fractures, and lack of detailed fault interpretation from poor seismic. Alternatively, to characterize the heterogeneous flow related with natural fractures in this undeveloped reservoir, fracture network is modelled based on core, bore hole imager (BHI), conventional logs, seismic data and test information. Limited by investigation scale, vertical wells record apparent BHI, and raw fracture interpretation cannot represent true 3D percolation reflected on PLT. To overcome this shortfall, correction based on geomechanics and mechanical layer (ML) analysis is performed. Young's modulus (E), Poisson ratio (ν), and brittleness index are calculated from logs, describing reservoir tendency of fracturing. Other than defining MLs, bedding plane intensity from BHI is also used as an indicator of fracture occurrence, since stress tends to release at strata discontinuity and forms bed-bounded fractures observed from cores. Subsequently, a new fracture intensity is generated from combined geomechanics properties and statistics average of BHI-derived fracture occurrence within the ML frame, which improves match with PLT and distinguishes fracture enhance flow intervals consistently in all wells. Seismic discontinuity attributes are used as static fracture footprints to distribute fractures from wells to 3D. The final hybrid DFN comprises large-scale deterministic zone-crossing fractures and small-scale stochastic bed-bounded fractures. Sub-vertical open fractures are dominated by NE-SW wrenching fractures related with Zagros compression and reactive salt upward movement. There is no angle rotation of fractures in different fault blocks. Open fractures in other strikes are supported by partial cements and mismatching fracture walls on computerized tomography (CT) images. ML correlation shows vertical consistence across stratigraphic framework and its intensity indicates fracture potential of vertical zones reflected by tests. Fracture-enhanced flow units are further constrained by a threshold in both combined geomechanics properties and statistics average of raw BHI fracture intensity in ML frame. As a result, final fracture network maps reservoir brittleness and flow potential both vertically and laterally, identifying fracture regions along folding axis not just major faults, evidenced by wells and seismic. According to the upscaling results, the case study reveals a type-III fractured reservoir, where fractures contribute to flow not to volume. Fracture network enhances bed-wise horizontal communication but also opens vertical feeding channels. Fracture permeability is mainly influenced by aperture and intensity, while aspect ratio, fracture length, and proportion of strikes and dips mainly influence permeability distribution rather than absolute values. This study provides a production-oriented characterization workflow of natural fracture heterogeneity based on correction of raw BHI in undeveloped fields.
Sweet gas accumulations in Permian-Triassic Khuff reservoirs are key players to meet growing gas demand in Abu Dhabi. In the study green field, thickness of seven Khuff reservoir units ranges between 100 ft to 500 ft with high variation in reservoir quality and productivity. Besides the pervasive faults and fractures related to salt-dome tectonics, complex pore systems play a major role in reservoir heterogeneity that impacts fluid distribution and flow behavior. The first whole well section cores recovered from the Upper Khuff in the study field were integrated with log data to establish a sequence framework and lithofacies scheme. Routine core analysis (RCA), thin section description and mercury injection capillary pressure (MICP) results were used to define pore systems and rock types at the core scale. Afterwards integrated with petrophysical log evaluation and well test results, secondary pore system with bimodal rock types were differentiated and distributed in sequence frame at well and field scale. The layer-cake sequence of Khuff Formation is composed of aggradation cycles of lagoonal and tidal to supra-tidal deposition across the study field. Primary reservoir rocks were developed in grainy facies with intergranular macro pores from shoals and moderate-energy lagoon settings. During later diagenesis, non-selective dissolution, dolomitization and late-stage cementation in these facies resulted in tortuous pore throat and low-connected secondary micro-meso pores. In low content of these secondary pores, it retains unimodal reservoir rocks dominant by macro-meso pores. With increasing complexity in these secondary pores, it develops bimodal reservoir rocks where low-connected to isolated micro vugs form the second peak on pore size distribution and shows a stair-step on saturation-pressure curve. On the other hand, increase of the meso pores leads to a gradient change in a wide range of pore size without obvious second peak, it tends to develop multimodal reservoir rocks that can be simplified by pseudo-unimodal pressure curve with a larger transition zone. Because of the isolated pores, some reservoirs of the secondary pore system are characterized by high irreducible water saturation (Swirr) and featured as low-resistivity pay zones, where high gas rates were achieved in high water saturation (Sw) intervals without water recovery. For these reservoirs, permeability estimation from cores and logs is biased by connected macro pores, high reservoir quality index (RQI) is reserved in high Sw. But water saturated in isolated secondary pores is immovable. As such secondary pore system can be differentiated from unimodal reservoirs on J-Function with high J values and high Sw high above contact. With the seismic data constrain and statistics analysis, secondary pore reservoirs can be stochastically modelled. And its contribution to reserve can be quantified. In summary, this case study provides a method to mimic the process and impact of secondary porosities in Khuff reservoir from core to field scale.
scite is a Brooklyn-based organization that helps researchers better discover and understand research articles through Smart Citations–citations that display the context of the citation and describe whether the article provides supporting or contrasting evidence. scite is used by students and researchers from around the world and is funded in part by the National Science Foundation and the National Institute on Drug Abuse of the National Institutes of Health.
hi@scite.ai
10624 S. Eastern Ave., Ste. A-614
Henderson, NV 89052, USA
Copyright © 2024 scite LLC. All rights reserved.
Made with 💙 for researchers
Part of the Research Solutions Family.