Leak-off tests (LOTs) or, preferably, extended leak-off tests (XLOTs), can be successfully used in minimum in-situ stress, S 3 , estimations. Selecting a point on the leak-off graph that represents the best proxy for S 3 can reduce inaccuracies in the use of LOTs as a means of determining S 3 . If the testing procedure is well conducted and recorded, picking the leak-off pressure (LOP) or instantaneous shut-in pressure (ISIP) gives equally valid estimates of S 3 . During testing, most of the pressure applied in the deduction of S 3 is exerted by the static mud column, particularly in overpressured settings where higher drilling mud weights are used. Since the mud column contributes such a large proportion of the applied pressure, estimating S 3 from tests conducted at greater depth means the observed small difference between LOP and ISIP has even less of an effect on the deduced S 3 value. The data used in this study show that LOP closely matches ISIP when considering multiple cycle XLOTs. It can therefore be inferred that the LOP is the fracture re-opening pressure and hence S h given that the assumptions made by the Kirsch equation for wellbore failure are upheld. This study also considers the implications for calculating the magnitude of S H .

Depleted hydrocarbon reservoirs are attractive targets for short-term gas storage with frequent injection and production cycles. Optimum well completion and injection-storage-production design in depleted reservoirs would require an understanding of important rock mechanical issues. These include drilling and completion challenges of new wells in low-pressure reservoirs accounting for potential rock fatigue due to cyclic injection/depletion and loading and unloading, and determination of maximum sustainable storage pressures that would avoid fracturing and fault reactivation. This paper describes a case study from a coal seam gas project considered for supply to a liquefied natural gas plant in Australia. The paper demonstrates a systematic approach for geomechanical risk assessments for short-term gas storage in depleted sandstone reservoirs. Depleted sandstone gas reservoirs at a depth of 1,000 m with existing pressures of 150–300 psi are considered in this study. Historical and new well data including cores, well logs, drilling, and field data such as injection and minifracture (minifrac) tests are used to develop a field-specific geomechanical model. Field data and laboratory measurements of rock mechanical properties are used to define the stress path factors and the change in in situ stress with depletion and injection in sandstone reservoirs in the study area. Rock mechanics tests on representative core plugs under cyclic loading and unloading simulating operating depletion and injection pressure conditions are used to assess the level of rock fatigue and rock weakening under cyclic loading. Geomechanical analyses show that despite a low fracture gradient in depleted reservoirs and the presence of non-depleted overburden rocks, new high-angled wells can be drilled safely with a relatively low mud weight in the non-depleted sections and with air in the reservoir section. Fracturing and faulting assessments confirm the critical pressures for fault reactivation and fracturing of intact rocks are beyond the planned storage pressures, and a maximum pressure of 200–300 psi beyond the initial reservoir pressures may be possible from fracturing or fault reactivation aspects. Sand production prediction evaluations indicate that new injection-production wells can be completed with no downhole sand control due to a very low risk of sanding even after considering rock weakening associated with cyclic loading. The methodology and overall workflow presented in this paper can be applied when carrying out geomechanical risk assessments for natural gas storage in depleted reservoirs.

Late Cretaceous obduction of the Semail ophiolite and underlying thrust sheets of Neo-Tethyan oceanic sediments onto the submerged continental margin of Oman involved thin-skinned SW-vergent thrusting above a thick Guadalupian–Cenomanian shelf-carbonate sequence. A flexural foreland basin (Muti and Aruma Basin) developed due to the thrust loading. Newly available seismic reflection data, tied to wells in the Gulf of Oman, suggest indirectly that the trailing edge of the Semail Ophiolite is not rooted in the Gulf of Oman crust but is truncated by an ENE-dipping extensional fault parallel to the coastline. This fault is inferred to separate the Semail ophiolite to the SW from in situ oceanic Gulf of Oman crust to the NE. It forms the basin margin to a “hinterland” basin formed atop the Gulf of Oman crust, in which 5 km of Late Cretaceous deep-water mudstones accumulated together with 4 km of Miocene and younger deep-water mudstones and sandstones. Syndepositional folding included Paleocene–Eocene folds on N-S axes, and Paleocene to Oligocene growth faults with roll-over anticlines, along the basin flank. Pliocene compression formed, or tightened, box folds whose axes parallel the modern coast with local south-vergent thrusts and reversal of the growth faults. This Pliocene compression resulted in large-scale buckling of the Cenozoic section, truncated above by an intra-Pliocene unconformity. A spectacular 60-km-long, Eocene(?) to Recent, low-angle, extensional, gravitational fault, down-throws the upper basin fill to the north. The inferred basement of the hinterland basin is in situ Late Cretaceous oceanic lithosphere that is subducting northwards beneath the Makran accretionary prism.

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