This investigation of naturally occurring fractures in the mafic rocks of the Palisades dolerite sill characterizes the porosity of this crystalline rock sequence, and yields a method of determining the in situ porosity when complete down-hole information is not available. Two holes, 229 m and 305 m deep, were drilled 450 m apart through the sill and into the underlying Triassic sediments of the Newark Basin. Both holes were logged with geophysical tools, including the acoustic borehole televiewer (BHTV), to identify intervals of high porosity, fracturing, and potential zones of active fluid flow. Using the BHTV data, 96 and 203 fractures were digitally mapped within the sill in Well 2 and Well 3, respectively. Most fractures dip steeply (76–78°). There is a shift in fracture orientation between Well 2 and Well 3, although the lithology of the sill is continuous. The dolerite penetrated in both holes is fresh and unaltered, and intersects a 7-m thick olivine-rich layer about 15 m above the bottom of the sill. Several fractures identified in the sill have large apparent aperture (>6 cm) that correspond to high-porosity zones (6–14%), measured from both resistivity and neutron logs in Well 2. We use a relationship between porosity and apparent fracture aperture in Well 2 to infer the porosity in Well 3. This correlative method for estimating porosity may be applicable between holes in other crystalline rock environments where down-hole log data are incomplete. Changes in the temperature gradient log also indicate active fluid flow, although flow appears to be most active in fractured and high-porosity zones in the sediments.

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.

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An integrated geomechanical model which describes the rock strength, fluid pressures, and in situ stresses for the Rang Dong Field, offshore Vietnam has been developed using drilling data, geophysical log data, seismic data, and production/well testing data. The field-wide state of stress was constrained by direct observation of drilling induced wellbore failure, including both breakout (BO) and drilling induced tensile fracture (DITF). Some of the fine-scale variation of the orientations of drilling induced failure relate to local influences of faults and/or fracture zones. These fine-scale features enable the understanding of how faults and fracturing in the basement are influencing the stress field. Rang Dong Field is characterized by a strike-slip state of stress, where the intermediate principal stress is vertical (Sv=S2), and the maximum and minimum horizontal principal stresses (SHmax=S1 and Shmin=S3) are horizontal. SHmax is oriented approximately 152° N (NNW-SSE). Development at Rang Dong Field has involved drilling of highly deviated, and in some cases horizontal, trajectories. These have been completed with some difficulty, depending on local conditions. In some cases nearly total fluid loss was experienced, and drilling was completed at depths as great as 4000 metres TVD with seawater and lubricant additives.

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