On the basis of structural style and differences in Late Cretaceous evolution, the carbonate platform in northern Oman and the allochthonous wedge comprising deepwater sediments and oceanic crust in the Oman Mountains form distinct structural domains. Imbrication associated with the emplacement of the Semail Ophiolite and predominantly SW-verging thrusting of the Arabian Platform margin culminated in the late early Campanian. The structural grain of NW-trending thrust faults and contractional folds contrasts markedly with the style and grain of the region immediately south of the Oman Mountains (our study area) and implies strong strain partitioning. Kinematic indicators from subsurface data, combined with the age of growth faulting, provide the basis for the interpretation that maximum horizontal stress was oriented NW-SE in this foreland region rather than NE-SW during the Campanian. The dominant tectonic control on the formation of faults is believed to have been an oblique “collision” of the Indian Continent with the Arabian Plate during the Santonian-Campanian. Deformation in this domain was dominated by distributed strike-slip and normal faulting. This period of faulting was significant for two reasons: (1) The faults both enhanced existing structures and formed new traps. They also allowed vertical migration of hydrocarbons from Palaeozoic reservoirs (e.g. Haushi clastic accumulations) into Shu’aiba and Natih carbonates above. Until that time, some 75 Ma ago, oil was retained in Late Palaeozoic and older traps. This period of deformation is a “Critical Event” within the context of Oman’s hydrocarbon distribution.(2) Faults with NNW and WNW orientations that developed at that time appear to be directly associated with important fracture systems that affect the productivity of several giant fields comprising Natih and Shu’aiba carbonate reservoirs (e.g. Lekhwair, Saih Rawl). Following this tectonic event, late Maastrichtian to Palaeocene uplift and erosion in excess of 1,000 m, is recorded by truncation of the Aruma Group and Natih Formation, as well as part of the Shu’aiba Formation below the base Cenozoic unconformity. Seismic velocity and porosity anomalies from Lekhwair field in the northwest to the Huqf-Haushi High in the southeast, provide additional support for the areal distribution of this event. Around the Lekhwair and Dhulaima fields, the circular to elliptical subcrop pattern below this unconformity does not support the notion of a peripheral bulge related to the emplacement of the allochthon. The stress field changed during the late Cenozoic with the opening of the Red Sea and Gulf of Aden, and the collision of the Arabian Plate with the Iranian Plate. NE-SW-oriented maximum horizontal stress during the late Cenozoic led to the formation of major folds resulting in, for example, the surface anticlines over the Natih and Fahud fields as well as causing inversion along the Maradi Fault Zone. This may also have led to the uplift of the Oman Mountains. The regional northerly subsidence caused by crustal loading of the Arabian Plate gently tilted traps during the Pliocene-Pleistocene from Lekhwair to Fahud.

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Summary The main objective of this study was to extract fracture data from multiple sources and present it in a form suitable for reservoir simulation in a fractured carbonate field in Oman. Production is by water injection. A combination of borehole image (BHI) logs and openhole logs from horizontal wells revealed that water encroachment occurs mostly through fracture corridors and appears as sharp saturation spikes across fracture clusters. Dispersed background joints have little flow potential because of cementation, lack of connectivity, or small size. Image logs indicate that fracture corridors are oriented dominantly in the west/northwest direction. Most of the several injector/producer short cuts are also oriented in the west/northwest direction, supporting the view that fracture corridors are responsible for the short cuts. Flowmeter logs from vertical injector or producer wells intersecting a fracture corridor show a step profile. A comparison of the injection or production history of wells with or without a step profile provided a means to calculate permeability enhancement by fracture corridors. The field has more than 300 vertical wells and nearly 20 horizontal wells, which allowed us to generate detailed fracture-permeability enhancement and fracture-corridor density maps based on injector and producer data, short cuts, mud losses, openhole logs, and BHI logs. We also were able to build stochastic 3D fracture-corridor models using corridor density from dynamic data and orientation from BHI logs and seismic data. Fracture-corridor length and width were tied to fracture-permeability enhancement using wells with both image logs and production data. The fracture-permeability enhancement maps were verified independently by waterflood-front maps. Notwithstanding the uncertainties, the fracture data were sufficiently accurate and detailed to generate both single- and dual-porosity simulation results with good field-scale history match.

This paper describes the procedure of building a probabilistic decision tree on the basis of the integration of data from multiple sources, conditional probabilities, and the application to map fracture corridors (FCs) in a mature oil field with abundant production data. An FC is a tabular, subvertical, fault-related fracture swarm that intersects the entire reservoir and extends laterally for several tens or hundreds of meters. Direct indicators of FCs, such as image logs, flow profiles, well tests, and seismic fault maps, are sometimes insufficient to map all FCs in a field. It is also necessary to use indirect FC indicators from well data, such as productivity index (PI), gross rate, water cut, and openhole logs. FCs from indirect indicators can be inferred by a probabilistic decision tree, which makes predictions by integrating data from multiple sources, giving preference to the indicators with the highest relevance. Decision trees are constructed by use of a training set that includes measurements of both direct and indirect FC indicators. In this study, wells with borehole images, production logs (flow profiles), and injector/producer short cuts are selected as the training set. The resulting decision trees reveal that total losses, gross production rates, and water cuts are the three most effective indirect indicators of fracture corridors in the test field. Direct FC Indicators in Boreholes.Borehole-image (BHI) logs are the main source of direct information on fractures and FCs. Both conductive and cemented fractures can be identified, and their attributes (e.g., dip, strike, aperture) can be measured with these logs. BHI logs are especially useful in horizontal wells because most fractures are subvertical and horizontal wells have a much higher chance of intersecting fractures than vertical wells.Pressure-transient tests (PTTs) offer the second-best source of direct information on both intersecting and nearby conductive or cemented FCs/faults. Furthermore, a PTT is the only means to measure length and conductivity of FCs. Production logs (flow profiles) also reveal intersecting FCs as jogs, or steps, in the profile of the flow log. The high permeability of fracture zones often