Abstract The Fram discovery, located in the UK Central North Sea, comprises the Paleocene-aged Forties Sandstone Member with an oil rim and primary gas-cap trapped within a four-way dip closure around a pierced salt diapir. The Forties Sandstone Member reservoir at Fram is characterized by very-fine- to fine-grained sandstones interbedded with shales with post-depositional small-scale slumping and sand injection, interpreted to be the product of high-density turbidity currents and debris flows. Deposition was in an overall distal and marginal, basin-floor lobe environment. The Forties reservoir interval is considered to comprise a series of offset-stacked, turbidite lobes characterized by a systematic variation from axial amalgamated sandstone facies to more distal, marginal and thinner-bedded heterolithic sandstone facies, producing an overall sheet-like reservoir architecture. The Forties reservoir at Fram is thinner and poorer when compared with more proximal parts of the Forties submarine fan system, and reservoir quality is strongly controlled by sedimentary facies. The architecture of the reservoir is expected to result in poorer vertical, but greater lateral, stratigraphic continuity when compared with more channelized Forties reservoirs such as the Nelson and Forties fields further to the north. A key step in understanding and characterizing the Fram reservoir was the appraisal drilling in 2009, which included coring, comprehensive wireline logging, formation pressure data acquisition and a drill stem production test. This paper provides an overview of the Fram reservoir geology and demonstrates how integration of data acquired in the 2009 29/3c-8,8z appraisal wells with 3D seismic datasets, existing E&A wells and analogues has helped to improve reservoir characterization and identify the major subsurface uncertainties needing to be addressed during the field-development planning.

Abstract The chalk reservoir of the Gorm Field, southern North Sea is dome-shaped and faulted owing to a combination of salt diapirism and regional east–west extension. Fractures developed in the structure considerably enhance permeability. The dataset discussed here records fractures in horizontal wells from more than 10 km of image logs and provides a special opportunity to test theoretical models of fracture development with quantitative observations. In an effort to forecast fracture density and fracture orientation, we have estimated the strains in the structure using an elastic dislocation model that incorporates mechanical boundaries in the form of the tectono-stratigraphic interface with salt and tectonic faults. More than 50% of the angular differences between poles to the planes of simulated and observed fractures are less than 30°; 75% are less than 45°. Relative strain magnitude appears to be a useful indicator of fracture density. At the field scale, small strain magnitudes correspond with small non-zero fracture densities and relatively large strain magnitudes correspond with high fracture densities.

Abstract The Merganser Field is located in the East Central Graben of the UK Central North Sea, and consists of a gas/condensate column trapped in a structural attic on the flanks of a fully penetrating salt diapir. A large salt overhang obscures the field and structural definition is challenging owing to poor seismic imaging. Exploration drilling established a column of 1327 ft in Paleocene-aged deep-marine deposits of the Forties, Andrew and Maureen Sandstone members, and revealed significant geological complexity. Depositional styles record the relationship between salt tectonics and sedimentation, with variable reservoir distribution influenced by halo-kinetically induced palaeorelief and accommodation space. Re-mobilization of sediments is observed at multiple scales, and includes centimetre-scale de-watering structures, decimetre-scale sand injectites and kilometre-scale olistoliths. Whilst the hydrocarbon properties are consistent, contact depths are variable. Pressure data indicate compartmentalization across the field, which is likely to be caused by either radial faulting or hydrodynamic effects. Owing to the magnitude of subsurface uncertainty, the Merganser discovery could not sustain the investment required for standalone facilities. The development of the neighbouring Scoter Field provided the requisite local infrastructure to progress Merganser into production. The Field Development Plan (FDP) estimated recovery of 100 bscf gas and 3 mmstb condensate, and focused on delivering a low-cost development solution consisting of two horizontal wells and a subsea tie-back that would be robust against the downside, yet maintain flexibility to optimize in an upside outcome. Pilot holes were drilled to establish top reservoir with the subsequent horizontal well trajectories being re-designed to reflect structural geometry. The reservoir sections would maximize connectivity between fault compartments and stratigraphic units, and positioning was optimized with well-site biostratigraphy. Each reservoir section exceeds 4000 ft and maintains at least 1000 ft vertical stand-off from the gas/water contact. The facilities include a 5 km subsea tie back to the Scoter production manifold, with metering at the Merganser manifold for allocation purposes. Gas and condensate are commingled with Scoter, and transported 11 km to Shearwater for processing. The gas is transported onshore through the Shearwater Elgin Area Line and condensate through the Forties Pipeline System to Kinneil. Field performance to date has exceeded the FDP P50 both in terms of daily rate and cumulative production. Early production rates peaked at 100 mmscf/day of gas and 6000 stb/day of condensate and, to end-2014, Merganser has produced 161 bcf of gas and 10 mmstb condensate. This performance is due to a combination of better than expected connectivity, high reservoir k h , lower draw-down afforded by long horizontal wells and compression at the Shearwater platform. Subsurface uncertainties prior to development were considerable and the ‘appraisal through development’ strategy has demonstrated that success is achievable through meticulous planning and scenario analysis.

Abstract Reservoirs at Pony-Knotty Head Field consist of stacked, middle Miocene (Serravallian) turbidites deposited as high-frequency low-stand successions within an increasingly ponded basin. Depositional elements include: (1) high to moderate permeability channel axes, channel margins, channelized lobes, and amalgamated lobes; and (2) those having low-permeability, such as marginal to distal lobes, levee-overbank debrites, slumped mudsheterolithics, and pelagic/hemipelagic muds. Fluid pressure data demonstrate that the Pony-Knotty Head Field is segmented into pressure compartments at multiple scales. Although the field is a low-dip, faulted, four-way turtle structure, interpreted faults are neither long enough nor have sufficient throw to segment reservoirs into observed pressure cells. Analyses of individual reservoir units indicate that variations in fluid potential are often greater vertically within wells than laterally between wells. This pattern indicates that at least some segmentation at this scale is due to low-dip stratigraphic barriers between depositional elements rather than to steeply dipping barriers, such as faults. At the field scale, both fluid pressures and depositional elements change vertically. Excess pressure was used to help define compartments at Pony-Knotty Head Field. (“Excess pressure” is the difference between pressure measured in a well and pressure calculated using a datum with an expected fluid gradient.) The deepest reservoirs have the lowest excess pressures. They are dominated by laterally continuous, unconfined depositional elements that bled excess pressure laterally. Progressively shallower reservoirs have progressively higher excess pressures in progressively more confined depositional elements. Between reservoirs of different depths and ages, stratigraphic complexity increased with time as increasing structural confinement of the depocenter above mobile salt drove stratigraphic evolution from a lobe-dominated system to a channelized lobe and levee-channel complex system. We propose that compartmentalization at this scale results directly from stratigraphic responses to the structural evolution of depocenters.

Abstract Salt (halite, NaCl) is the most soluble of common rocks; it is dissolved readily and forms a range of subsidence or collapse features as a result of human activities. Bedded or domal salt deposits are present in 25 of the 48 contiguous United States and underlie nearly 20% of the land area. These salts occur in 17 separate structural basins or geographic districts in the United States, and either local or extensive examples of natural or man-made salt karst are known in almost all of these basins or districts. Human activities have contributed to the development of salt karst. Boreholes or underground mines may enable (either intentionally or inadvertently) unsaturated water to flow through or against the salt deposits, thus allowing development of small to large dissolution cavities. If the dissolution cavity is large enough and shallow enough, successive roof failures can cause land subsidence or catastrophic collapse. Because salt dissolution proceeds rapidly, human-induced karst features often develop quickly and with dramatically adverse impacts. Industries associated with local salt-dissolution and collapse features include solution mining (e.g., Cargill sink, Kansas; and Grand Saline sink, Texas), petroleum activities (e.g., the Wink sinks, Texas; Panning sink, Kansas; and Gorham oil field, Kansas), and underground, dry mining of salt (e.g., Jefferson Island mine, Louisiana; and Retsof mine, New York).