A reservoir fluid system can be roughly categorized by its vapor-liquid phase behavior, ranging from dry gas, wet gas and retrograde gas to volatile oil, black oil or heavy oil. The pressure, volume and temperature (PVT) behaviors of the fluids are important input parameters to reservoir simulators that engineers use for predicting phase and compositional changes as fluids flow from the reservoir to the refinery.
Fluid properties determine how reservoir fluids interact with each other and with the rock. Basic fluid properties include: density, fluid mass per unit volume; viscosity, a fluid's resistance to flow; and compressibility, the fluid volume change in response to pressure variation. Typically, oils at reservoir conditions contain gas in solution. Consequently, important oil properties include the oil formation volume factor, the volume ratio for oil at the surface over its volume at reservoir conditions, and the solution gas oil ratio, the ratio of the volume of gas dissolved per unit volume of oil, especially at the oil's bubblepoint pressure—the pressure below which the dissolved gas begins to come out of solution.
Reservoir fluids often flow from the subsurface as mixtures of oil, gas and water. Important multiphase transport properties include: relative permeability, the relative ease for one fluid to flow through the pore space in the presence of other fluids; wettability, the preference for a solid to be wetted by, or in contact with, one fluid rather than another; and capillary pressure, the buoyancy difference between the nonwetting and wetting phases competing for pore-space access. These properties affect the fluids' relative distribution, or saturation, in a rock's pore volume and their transport through it.
Pressures and Flow Rates
Field data for predicting and evaluating fluid flow in reservoirs come from transient tests and production logging conducted in wells. These data complement production data—the record of fluids produced from and injected into the reservoir—and help to explain patterns of pressure, flow rate and production volume variation across a field. In addition, the data are used to calibrate reservoir simulation models.
Reservoir engineers use data from transient testing to analyze and interpret reservoir pressure and flow rate behavior by taking measurements while intentionally varying the flow rate. This flow can be obtained by a downhole logging tool at the scale of liters, or the flow can be determined at reservoir scale while the operator is temporarily producing a well. Pressure-transient tests are conducted after either periods of no flow to establish static pressure conditions or periods of flow to establish stable flow rate conditions. During the test, flow is either reestablished or stopped and the downhole pressure is monitored. The flow rate changes cause pressure transients, or disturbances, that propagate away from the well and into the formation. Eventually, these pressure disturbances dissipate, and the pressure achieves a steady value in a reservoir. Rate transient tests are conducted by monitoring long-term flow tests for variations in the flowing pressure and rate behavior that are indicative of various flow regimes as the transient migrates away from the well and deep into the formation. Engineers watch for characteristic behaviors such as radial flow from a well, linear flow from a hydraulic fracture and, during long-term tests, the effects of reservoir boundaries; these boundaries may be impermeable and not allow flow, may be at constant pressure or may be a fluid source or sink.
Production logging is another form of formation evaluation in producer and injector wells. Engineers use production logging to determine from which zones fluids enter producing wells and into which zones fluids exit for injection wells. Production logging is also used to quantify flow rates, fluid contributions to the total flow volume and fluid properties at downhole conditions.
Reservoir engineering is important to all aspects of hydrocarbon production. It is central to engineers' ability to evaluate formation properties, forecasting production, improving efficiencies and cutting costs. Using improved forecasts from these tools, operators are better equipped to make field development decisions.
Oilfield Review 2016.
Copyright © 2016 Schlumberger.
For help in preparation of this article, thanks to Cosan Ayan, Clamart, France; and Chip Corbett, Houston, Texas, USA.