Updip

Key Takeaways

• Updip well locations in structurally tilted reservoirs have systematically better production characteristics than downdip locations in the same reservoir: an updip producer (drilled into the structurally higher portion of the oil column, farther from the oil-water contact) encounters the maximum oil column thickness at its structural position, has the lowest initial water cut (the oil-water contact is farthest from the perforated interval), and benefits from gravity drainage of oil from above if the reservoir has good vertical permeability; a downdip producer (drilled near the oil-water contact) has a thin oil column, high initial water cut, and rapid water breakthrough as oil depletion draws the contact upward; the structural relief available for updip development (the vertical distance from the oil-water contact at the well location to the crest of the structure) is the primary determinant of the cumulative oil recovery per well and the producing life before water breakthrough, with higher updip locations generally providing longer dry-oil production periods before waterflood breakthrough; the updip preference in development drilling is balanced against the practical constraint that the most updip position (the structural crest) may have the highest risk of gas cap contact if the gas-oil contact is close to the drilled interval, requiring careful structural mapping to identify the optimal updip-but-below-gas-cap position for each development well.
• Updip migration is the process by which oil and gas generated in a source rock (typically an organic-rich shale or marl at depth) migrate toward the surface through carrier beds (permeable sandstones or carbonates) in the direction of increasing buoyancy, which in a dipping formation is the updip direction; the driving force for updip migration is the density difference between the buoyant hydrocarbon and the denser pore water, which creates a net upward force on the hydrocarbon that drives it in the direction of decreasing depth (updip) within the carrier bed; oil and gas continue migrating updip until they encounter a trap (a structural or stratigraphic barrier that prevents further updip migration and forces the accumulation to grow in volume as more hydrocarbons arrive), where they accumulate until the trap is filled to the spill point (the lowest structural position on the trap's updip closure); hydrocarbons that spill over the trap's spill point continue migrating updip to the next structural closure, creating a series of en-echelon oil accumulations along a regional migration fairway; the recognition of updip migration pathways is a fundamental concept in petroleum systems analysis used by exploration geologists to identify which structures along a regional dip direction are likely to be charged with hydrocarbons and which are below the migration path and therefore unlikely to contain accumulations.
• Updip injection in enhanced oil recovery (EOR) refers to the injection of gas (or less commonly water) into the updip portion of a tilted reservoir to create a gravity-assisted displacement drive that sweeps oil downdip toward producers located in the lower parts of the oil column: gas injection updip into the gas cap (or into the updip edge of the oil column) expands the gas cap downward and pushes oil downdip toward downdip producers, utilizing gravity segregation to improve the sweep efficiency of the gas flood; this updip gas injection strategy (used in the Prudhoe Bay field in Alaska, the Forties Field in the North Sea, and many other large tilted reservoirs) achieves higher displacement efficiency than a gas flood injected at arbitrary positions because the density difference between the injected gas and the reservoir oil creates a stable gravity front that sweeps oil efficiently as long as the injection rate is below the critical rate above which gravity override (the tendency of the less dense gas to bypass the oil and channel updip above it) destabilizes the front; the optimal injection rate for gravity-stable updip gas injection is constrained by the critical rate equation derived from the Buckley-Leverett theory, which balances the viscous displacement force against the gravity segregation force at the injection front.
• Updip faults as hydrocarbon traps occur when a sealing fault (a fault whose gouge zone or juxtaposition creates a barrier to fluid flow) cuts across a dipping reservoir and prevents updip migration of hydrocarbons, creating a fault trap in which the oil column is bounded updip by the fault seal and downdip by the oil-water contact in the reservoir: the fault acts as a synthetic seal (preventing hydrocarbons from migrating updip past the fault plane) or as a lateral seal (preventing migration laterally along the fault zone) for oil and gas accumulations in the hanging wall or footwall block; the sealing capacity of an updip fault (the maximum hydrocarbon column height the fault can retain before the seal fails and hydrocarbons leak updip across the fault) is determined by the capillary entry pressure of the fault gouge (the pressure required to force oil through the water-wet fault zone), which depends on the clay content, grain size, and diagenesis of the fault gouge material; fault seal analysis is a critical component of prospect risking for updip fault traps, because a fault that fails to seal will allow hydrocarbons to migrate past the trap and accumulate at the next updip closure, making the prospect dry; conversely, an updip fault that seals completely may hold an oil column that extends significantly above the spill point of a conventional four-way structural closure, adding unrecognized reserve potential that can be identified by careful fault seal analysis.
• Geosteering of horizontal wells to maintain an updip trajectory within the target reservoir interval is one of the most important applications of real-time formation evaluation in unconventional and conventional horizontal well development: in a reservoir with a significant dip (2 to 10 degrees from horizontal), a horizontal well drilled exactly at the dip angle of the formation will maintain a constant depth within the formation throughout the lateral; if the well is drilled updip (slightly steeper than the dip of the formation), it will gradually rise in the formation and eventually exit through the top of the reservoir interval; if the well is drilled downdip (slightly less steep than the formation dip), it will gradually descend in the formation and eventually exit through the base of the reservoir; the geosteering decision to maintain an updip position (staying near the top of the oil-bearing interval) is preferred in reservoirs with bottom water drive (where maintaining the well above the rising oil-water contact maximizes the dry oil production period) and in tight oil reservoirs where the best rock quality (highest porosity and organic content in shale reservoirs) is concentrated in the upper portion of the target formation; real-time LWD (logging while drilling) measurements of gamma ray, resistivity, and density-neutron are used by the geosteering geologist to detect approaching formation boundaries and adjust the well trajectory to maintain the desired updip position within the target interval.