ALBERT

Description: The Upper Permian–Carboniferous Unayzah Formation in South Haradh, Saudi Arabia, includes two major mechanical and petrophysical layers that are separated by shale-rich zones. Open tectonic fracture clusters are rare and not essential for fluid flow in the Unayzah A zone, which has high porosity and permeability. However, such fracture clusters are essential to, and impact, the production performance in the Unayzah B/C tight-gas reservoir. The occurrence of the tectonic fractures in the Unayzah Formation is linked to the rock mechanical properties, which vary with porosity, shale volume, cement type, and texture. The B/C unit is more fractured than the A unit, but its layers vary in the degree of fracturing. The variation in fracture development within the B/C unit results in differences in fracture-enhanced permeability based on production profiles where flow is restricted to preferentially fractured mechanical layers that lack effective vertical fluid communication with other layers. We identify two tectonic fracture systems: an older subordinate fully mineralized system and a younger primary mostly open system. Early extensional fractures including joints and faults developed parallel to the basement faults during the opening of the Neotethys. These are fully mineralized and have little or no function as fluid conduits. The younger system includes open-fracture clusters that are predominantly parallel or nearly parallel to the regional east-northeast–west-southwest maximum horizontal stress of the Zagros (that has been active since the Late Cretaceous) and is independent of local structures. Therefore, these fractures are controlled by remote stresses instead of the basement-rooted forced folds and faults. In this article, we demonstrate that in the Unayzah B/C, natural fractures are essential to permeability and, in some areas, to porosity, and thence, to reservoir performance. The results of this study are being implemented in well placement and completion design to optimize the intersection of open-fracture clusters with positive preliminary results.

Description: The highly variable performance of the Permian–Triassic Khuff reservoir in onshore Saudi Arabia has been attributed to the presence of natural fractures. Similar preproduction pressure profile and hydrocarbons in the different reservoir units in some fields have been attributed to vertical communication through large faults. To validate these assumptions, we studied the static and dynamic data from the Khuff reservoir in 19 major structural traps. We identified two distinctive fracture domains based on fracture orientation and density. Fracture evolution is mainly controlled by the extensional and consequent compressional plate tectonics instead of local structures. In-situ stresses are dominated by the Zagros plate tectonics and affect fracture aperture differently in the two fracture domains. The fracture impact on the Khuff reservoir performance is mostly subtle because of the nature and distribution of the fractures. High fracture-enhanced productivity occurs locally in some of the producing wells, and it results from high-density fracture clusters (including mesoscopic faults) with channel-type apertures. The following findings challenge the perceived major functions of fractures in the Khuff reservoir performance in onshore fields: (1) Individual fractures are dominantly tensile and small (mesoscopic and microscopic); (2) individual faults are small and not readily resolvable at seismic scale; (3) the depth and carbonate nature of the Khuff reservoir make the fractures highly susceptible to fast healing unless preserved within the hydrocarbon column; (4) initial vertical pressure gradient changes with production indicate a lack of present-day communication across the anhydrite sealing layers, between the different Khuff reservoir units; (5) horizontal well direction does not generally have an impact on productivity; and (6) sustained and heavy losses of circulation are rarely encountered in the Khuff reservoir wells. Mohammed S. Ameen received his Ph.D. and Diploma of Imperial College in structural geology and geomechanics from Imperial College, London, 1988. He has more than 20 years of academic and industrial experience and has patented a new method for the characterization of microfractured reservoirs. He has published 25 articles on fractures and folds, and has edited three special publications for the Geological Society (London). He conducted the first classic work on the fractures and folds across the Taurus-Zagros Range, Iraq, covering 30 major fold traps. The work is published in the AAPG Bulletin, the Geological Magazine, and the Journal of Petroleum Geology. He joined the Reservoir Characterization Department at Saudi Aramco in 1998. Since 2004, he has been leading the Structural Geology and Rock Mechanics Group in the Geological Technical Services Division, Saudi Aramco. He is an active member of the AAPG, Society of Petroleum Engineers, European Association of Geoscientists and Engineers, and the Geological Society (London). Ismail M. Buhidma is a petroleum engineering consultant in the Gas Reservoir Management Division of Saudi Aramco with 32 years of diverse industrial experience. For the last 12 years, he has been actively involved in Aramco's nonassociated gas development program. His areas of interest include reservoir management, well performance analysis, well test analysis, phase behavior, geomechanics, reservoir simulation, reservoir characterization, and well stimulation. Prior to joining Aramco, Ismail worked for Exxon in Libya, Schlumberger and Atlantic Richfield in the USA, and Qatar Petroleum in Qatar. Ismail holds B.S. and M.S. degrees in petroleum engineering from the University of Tulsa. He is a member of Society of Petroleum Engineers (SPE) and has published numerous SPE appears. Zillur Rahim is a petroleum engineering consultant with Saudi Aramco working in gas field development. He received his B.S. degree from Algerian Petroleum Institute and M.S. degree and Ph.D. from Texas A&M University, College Station, all in petroleum engineering. He has 25 years of industry experience, has published more than 50 technical papers, and has taught numerous industry courses. Previously, he worked with Holditch and Associates Petroleum Consultants and with Schlumberger Reservoir Technology group. His area of expertise includes reservoir engineering, hydraulic and acid fracturing, and reservoir management.

Description: This article presents a test case of a new technology using artificially enhanced anisotropy of magnetic susceptibility (referred to here as EAMS) for the characterization of microfractured reservoirs. These are reservoirs in which microfractures are essential to porosity and/or permeability. A conventional geological characterization is costly, time consuming, and difficult to quantify in terms of assessing fracture impact on porosity and permeability. Therefore, an efficient and effective method is required to characterize these microfractures and to determine their contribution to porosity and permeability. The EAMS technology, which we developed and tested, allows rapid analysis that bridges reservoir geology and engineering. Using petrography, the margin of error to detect microfractures that impact porosity and/or permeability is 43%; however, it requires three times the sampling rate of the new EAMS technology. The lower part of the Unayzah reservoir (Unayzah-B/C) in the Wudayhi field, Saudi Arabia, where fractures were studied and microfractures are known to impact reservoir performance, is used to develop and verify the EAMS technology. The results show that EAMS-derived microfracture fabric strikes east-northeast–west-southwest, consistent with that obtained by geological means. The effective-porosity profile obtained from EAMS tests is similar to that of the conventionally acquired porosity. Open microfractures in tested samples increase mean values of reservoir effective porosity by 36–50% in Unayzah-B/C. The occurrence of connected microfractures is estimated to cause an increase in average permeability of 75% in Unayzah-B/C. This is in agreement with the fact that wells in microfractured Unayzah-B/C have 4.5–14 times the productivity of wells as nonfractured sections of this reservoir. A maximum permeability trend of northeast-southwest permeability anisotropy is detected. The implementation of the EAMS technology in other fields with microfractured reservoirs will directly impact operational and simulation effort. Mohammed S. Ameen was awarded his Ph.D. and D.I.C. in structural geology and geomechanics from Imperial College, London, in 1988. He has more than 20 years of academic and industrial experience. He joined the Reservoir Characterization Department in Saudi Aramco, in 1998, and is currently leading the Structural Geology and Rock Mechanics Group in the Geological Technical Services Division, Saudi Aramco. He is an active member of the AAPG, Society of Petroleum Engineers, European Association of Geoscientists and Engineers, and the Geological Society (London). Ernest A. Hailwood graduated from the University of Newcastle upon Tyne, United Kingdom, with a Ph.D. in paleomagnetism in 1971 and joined the University of Southampton, where he became head of Marine Geology and Geophysics and established a highly successful research laboratory specializing in sediment magnetism. He founded the company Core Magnetics in 1992 to provide services in paleomagnetic and rock magnetic measurements for the hydrocarbon industry.