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Shell Offshore Inc.’s Mississippi Canyon Block 731 Field (Mensa) is a large turbidite reservoir in 5300-ft (1615 m) water depth containing estimated in-place reserves of over 1.3 TCF of dry gas. The field is currently producing over 240 MMCFGD out of three wells, connected to a subsea manifold located 5 mi (8 km) away. The gas and associated condensate (1.75 bbls/mmcf) is carried through a 63 mi (101 km) flowline to Shell’s West Delta 143 platform for processing. There are limited opportunities to intervene in such a system, and any additional work in the field (e.g. recompletions/workovers) is very costly. An understanding of the reservoir geology is critical to optimize the development and minimize the need for future intervention work.

The vast majority of the gas reserves is in the Late Miocene “I” sand, an amalgamated sheet sand deposited as a fan in a relatively unconfined basinal setting. Salt withdrawal on the south end of the basin provided accommodation space (Table 1), and the fan is proximal to a sediment entry point on the northwest edge of the field. Based on 3-D seismic and two well penetrations (the discovery and appraisal wells), the “I” reservoir was originally modeled as a very homogeneous sand connected to a large aquifer to the south that provided the field’s drive mechanism. However, when production from the first well commenced, initial pressure measurements did not support this model, and reservoir simulations using these data suggested that the “I” sand was primarily a depletion-drive reservoir with little or no aquifer support. This had serious negative implications for the estimated recoverable reserves and the development strategy; the 63 mi (101 km) flowline and glycol-based hydrate inhibition system requires maintaining a reservoir pressure above 3200 PSI over the lifetime of the field with the support of a large, well-connected aquifer.

The Mensa subsurface team re-mapped the field using a high-frequency seismic dataset that had not been previously available. The team re-evaluated both the geologic model for the “I” sand and other new but smaller gas reservoirs encountered in the last production well to be drilled in the field (MC-687 A-2). The results suggested that the original geologic model for the “I” sand was overly simplistic. The reservoir is now viewed to be an amalgamated sheet sand complex, with at least two distinct sand lobes seen seismically and in well logs, one cutting down into the other, and with the possibility for there being at least a partial permeability barrier between them. Some of the new reservoirs seen in the A-2 well appear to be juxtaposed with the “I” sand across a series of faults within the field, providing additional reserves that could be at least partially drained by the three producing wells. An erosional bypass (Table 1) channel partially bisects the “I” sand aquifer and may help to limit the amount of pressure support that the aquifer can provide. The aquifer itself may be composed of several sand lobes that may not fully communicate with each other, although there is no current evidence seismically and there are no wet “I” sand penetrations. The presence of partial permeability barriers in the “I” sand, either from a post-depositional bypass channel or internal baffles, could give an early pressure history that would suggest a depletion drive. Over time, however, the team expects that these internal barriers, if present, will break down as the pressure differential across them increases (this has been Shell’s experience elsewhere, e.g. Shell’s South Timbalier 292 Field), and the reservoir will then behave more like an aquifer-driven system. Recent pressure data appear to confirm this and no change in the development is planned at this time.

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