Injection Test

Key Takeaways

• Step-rate tests (SRT) and extended leak-off tests (XLOT) are injection tests specifically designed to determine the formation fracture initiation pressure and fracture closure pressure, providing the critical wellbore integrity data needed for mud weight design in drilling (to ensure that drilling fluid pressure does not fracture the formation unintentionally) and for hydraulic fracture design (to provide the minimum horizontal stress magnitude that determines the fracture closure pressure): a step-rate test is conducted by injecting fluid at a series of increasing rates, recording the injection pressure at each rate after it stabilizes, and plotting the stabilized injection pressure versus rate; below the fracture initiation pressure, the plot shows a linear relationship between pressure and rate (as predicted by Darcy's law for matrix flow), but above the fracture initiation pressure, the pressure increases more slowly with increasing rate as the fracture opens and accepts fluid at the fracture gradient pressure; the fracture initiation pressure is identified as the breakover point where the slope of the pressure-rate plot decreases; the extended leak-off test (XLOT) monitors the pressure continuously during injection at a constant rate and identifies the fracture initiation pressure as the first deviation from the linear pressure increase that occurs when the formation begins to fracture; the fracture closure pressure (the pressure at which the fracture closes after injection stops and the pressure declines) is determined from the pressure decline after the XLOT by identifying the point where the pressure decline slope changes, corresponding to the transition from fracture closure (with fluid squeezed from the closing fracture contributing to pressure maintenance) to matrix storage-dominated pressure decline.
• Injectivity tests for water injection wells in secondary recovery and pressure maintenance programs determine the well's ability to accept the designed injection rate at a wellhead pressure below the formation fracture pressure, using injection at multiple rates to construct an injectivity index (II = q / delta_P, where q is the injection rate and delta_P is the difference between the injection pressure and the reservoir pressure, in barrels per day per psi) that characterizes the well's capacity: a high injectivity index indicates that the formation has high permeability and that the designed injection rate can be achieved at wellhead pressures well below the fracture pressure, providing operational flexibility; a low injectivity index indicates that the formation has low permeability or that the well has a positive skin (formation damage around the wellbore) that restricts fluid entry, requiring either higher injection pressures (risking fracturing the formation above the intended pressure) or reduced injection rates that may not meet the pressure maintenance targets of the flood design; matrix acidizing of the injection well (pumping HCl or HF acid into the near-wellbore formation to dissolve formation damage) can improve the injectivity index by removing the skin, reducing the required injection pressure for a given rate; in carbonate injection wells, the injectivity can be very high due to natural fractures or vuggy porosity, but the high injectivity may concentrate injection in specific fracture pathways and bypass the matrix reservoir, reducing sweep efficiency in the waterflood — a diagnostic situation where the well test injectivity data must be interpreted in conjunction with tracer test results and production surveillance data.
• Falloff testing (the analysis of pressure decline after injection is stopped) provides the same formation property information as a pressure buildup test after production, using the same Horner plot and log-log derivative diagnostic analysis methods: when injection is stopped, the wellbore pressure falls from the injection pressure toward the reservoir pore pressure (rather than building from flowing pressure toward static pressure as in a buildup test), and the pressure decline (falloff) is analyzed using the same superposition time and log-log derivative methods; the Horner plot for a falloff test uses the injection time and rate to compute the superposition time, and the extrapolation of the Horner line to infinite shut-in time gives the initial reservoir pressure (if the reservoir was at static pressure before injection began) or the average reservoir pressure in the drainage area if significant injection has already occurred; the log-log derivative of the pressure falloff identifies flow regimes (wellbore storage, radial flow, boundaries) by the slope of the derivative, exactly as in the equivalent buildup analysis, and the radial flow derivative plateau gives the formation permeability-thickness (kh) from the Horner slope relationship; complications in falloff analysis that do not occur in buildup analysis include the possibility that the injected fluid (water) has a different viscosity and compressibility than the reservoir fluid (oil), requiring a composite reservoir model that accounts for the mobility contrast between the injected and reservoir fluid banks when the injected fluid has displaced the original reservoir fluid to create a saturation bank around the wellbore.
• CO2 injection tests for geological carbon sequestration (CCS) evaluate the injectivity, storage capacity, and containment of the target saline aquifer or depleted reservoir formation before committing to large-scale CO2 injection that may continue for decades: a pilot injection test in which a relatively small volume of CO2 (hundreds to thousands of tonnes) is injected at a monitored test well surrounded by observation wells provides the critical data on formation injectivity (well productivity index for CO2 as a supercritical fluid, which has different viscosity and density from brine), the plume migration behavior (confirmed by comparison of the observed pressure response at observation wells with predictions from the reservoir simulation model), and the seal integrity (confirmed by monitoring for CO2 breakthrough above the cap rock using downhole pressure gauges, shallow monitoring wells, and surface gas flux measurements); the injection test also validates the pre-injection reservoir characterization including the permeability-thickness of the storage formation, the heterogeneity of the formation that will determine CO2 trapping by stratigraphic and dissolution mechanisms, and the absence of seal-bypassing faults or abandoned wells that could provide escape pathways for the injected CO2; regulatory frameworks for CCS projects (the EPA Underground Injection Control program, the EU CCS Directive) typically require injection tests and associated monitoring as part of the site characterization and permit application process before large-scale injection is authorized.
• Interference tests and pulse tests between injection and observation wells measure the hydraulic connectivity and diffusivity of the formation between the wells by analyzing the pressure response at the observation well caused by injection (or rate changes) at the injection well: an interference test involves injecting at a constant rate in one well while monitoring pressure at a distant observation well, and the time at which the pressure response is first detected at the observation well (the time of pressure interference) gives the hydraulic diffusivity (alpha = k / (phi * mu * ct)) of the formation between the wells; the magnitude and shape of the pressure response at the observation well (analyzed using log-log or type curve matching methods) provides additional constraints on the formation permeability, porosity, and the presence of barriers or conduits between the wells; pulse tests use periodic rate changes (injection-shutin cycles) at the injection well, with the pulsed pressure signal detectable at the observation well being analyzed to give the inter-well formation diffusivity with higher time resolution than a steady injection interference test; in enhanced oil recovery projects, interference tests between injectors and producers provide direct evidence of whether the reservoir connectivity between the injection and production pattern is adequate to support the designed injection-production ratios and to sweep the target reservoir volume between the well pattern.