Pressure Depletion

Key Takeaways

• The material balance equation (MBE) is the fundamental reservoir engineering tool for quantifying pressure depletion behavior, relating the cumulative production from the reservoir to the corresponding pressure decline through the compressibilities of all fluid and rock phases and the aquifer influx: the general material balance equation (Havlena-Odeh form) states that the underground withdrawal (production) equals the expansion of the oil and dissolved gas plus the expansion of the gas cap plus the expansion of the connate water and rock plus the water influx from the aquifer; plotting production withdrawal versus pressure drop on a p/z plot (for gas reservoirs, where cumulative production versus p/z yields a straight line for a volumetric reservoir with no water influx) or on a Havlena-Odeh plot allows the reservoir engineer to identify the drive mechanism, estimate original fluids in place, and project future production rate and pressure as a function of cumulative production; a linear p/z plot for a gas reservoir confirms volumetric depletion with no aquifer support, and the x-intercept of the extrapolated line gives the original gas in place (OGIP); curvature in the p/z plot (bowing above the straight line) indicates aquifer influx supplementing the gas expansion, while curvature below the straight line (unusual) suggests abnormal compressibility behavior; the MBE analysis provides the empirical basis for calibrating the reservoir simulation model used for production forecasting and development planning.
• Solution gas drive, the primary depletion mechanism in undersaturated oil reservoirs below the bubble point, is one of the least efficient recovery mechanisms available to the reservoir engineer because the dissolved gas that comes out of solution as reservoir pressure falls below the bubble point initially forms isolated gas bubbles that are not mobile and do not contribute to oil displacement until the gas saturation exceeds the critical gas saturation (typically 2-8% pore volume); above the critical gas saturation, the gas phase becomes continuous and mobile, but gas mobility (permeability-to-gas divided by gas viscosity) is much higher than oil mobility (permeability-to-oil divided by oil viscosity), causing the gas to override and channel preferentially to producing wells without effectively displacing the oil it bypasses; the result is rapidly rising gas-oil ratio (GOR) in producing wells, declining oil rate at progressively higher and more expensive gas handling requirements, and ultimate recovery factors of only 5-25% of original oil in place from solution gas drive alone, compared to 30-50% achievable with waterflood pressure maintenance; secondary recovery by water injection, typically initiated well before the reservoir pressure falls to the bubble point, maintains the reservoir above the bubble point (keeping the oil undersaturated and at maximum viscosity advantage) and displaces oil by piston-like displacement at much higher efficiency than solution gas drive; the timing of water injection initiation (before bubble point for maximum efficiency, but requiring early infrastructure investment that is expensive in frontier or deepwater environments) is one of the key field development optimization decisions that determines ultimate recovery from oil reservoirs.
• Compaction drive and subsidence resulting from pressure depletion are important in reservoirs with compressible rock frameworks (high-porosity chalk, weakly cemented sandstone, unconsolidated sand, and diatomite) where the reduction in pore pressure allows the overburden load to be increasingly supported by the rock grains rather than by the pore fluid, causing the rock to compact and expel additional fluid: the North Sea Ekofisk chalk field and the Groningen gas field in the Netherlands are the most studied examples of reservoir compaction causing surface subsidence (the upward-propagation of the volumetric strain to the sea floor or ground surface), with Ekofisk experiencing over 9 meters of seafloor subsidence since production began in 1971 and Groningen causing measurable land subsidence and induced seismicity from shear failure on pre-existing faults activated by pore pressure reduction; compaction drive provides additional energy for fluid expulsion beyond the fluid and formation compressibility term in the standard material balance equation, and in highly compressible reservoirs the rock compaction term can equal or exceed the fluid expansion term as a source of drive energy; however, compaction also reduces absolute permeability (pore throat collapse reduces the effective flow path area), which partially offsets the energy benefit of compaction drive by impeding fluid flow to producing wells; reservoir geomechanics modeling (coupling flow simulation with geomechanical deformation models) is required to capture the interplay between compaction drive, permeability reduction, and surface subsidence in compacting reservoirs.
• Depletion-induced stress changes affect hydraulic fracturing in unconventional reservoirs through two distinct mechanisms: interstage depletion (the reduction of pore pressure in previously fractured stages adjacent to a new fracturing stage) and inter-well depletion (the reduction of pore pressure in the drainage area of existing producers adjacent to a new well being fractured): interstage depletion reduces the minimum horizontal stress in the depleted zone (by approximately the Biot coefficient multiplied by the pore pressure reduction multiplied by the ratio of the horizontal to vertical poroelastic moduli, typically 0.5-0.8 times the pore pressure reduction), so that the hydraulic fractures from a new stage or a refracture treatment in a depleted zone preferentially propagate toward the low-stress depleted region rather than into the undepleted virgin formation between wells or between stages; the phenomenon of "frac hits" or "inter-well communication" occurs when a new fracture propagates through the depleted inter-well region and reaches an existing producing well, causing a pressure pulse (a sudden increase in wellhead pressure) in the existing well that indicates hydraulic connection; frac hits cause both operational problems (disrupting production from the existing well during and after the new fracturing treatment) and reservoir management challenges (indicating that some of the new fracture energy is being spent on depleted rock rather than undrained virgin reservoir); depletion mapping (tracking the spatial extent of pressure depletion between wells using production history matching and pressure transient analysis) is used to design fracturing programs that avoid or minimize frac hits in developed pads.
• Pressure depletion monitoring through periodic static reservoir pressure measurement (from pressure buildup tests, repeat formation tests, or permanent downhole gauges) provides the data required to calibrate the reservoir model and to evaluate the effectiveness of pressure maintenance programs: the average reservoir pressure at any time in the depletion history is a function of the cumulative fluid withdrawal and the reservoir compressibility and drive mechanisms, and the difference between the measured reservoir pressure and the pressure predicted by the calibrated material balance model indicates whether the model assumptions (reservoir volume, aquifer strength, drive mechanism) are correct; declining reservoir pressure faster than the model predicts indicates either a smaller reservoir volume than assumed (less connected pore space than estimated), a weaker aquifer than assumed, or higher permeability communication to adjacent depleting formations; rising reservoir pressure faster than predicted indicates either a stronger aquifer than assumed or production of less fluid than recorded (due to meter errors or commingled production from multiple zones where the zone contributions are not individually metered); the pressure depletion history of the reservoir, plotted on a p/z diagram or a production history plot against cumulative production, provides the most reliable single data set for reservoir volume estimation and recovery factor forecasting, surpassing static volumetric estimates from seismic and well data that are subject to structural and petrophysical uncertainties that the production-pressure history effectively constrains.