Openhole Test

Key Takeaways

• Drillstem test (DST) openhole assemblies use an inflatable or compression-set packer to isolate the test interval from the mud column above, an interval control valve (ICV) or drill string tester valve (DSTV) to open and close the test interval to the drill string bore, and a downhole pressure gauge to record formation pressure continuously during the test sequence: the DST sequence begins with an initial shut-in period (ISI, 10-60 minutes) during which the formation pressure equilibrates to the static pressure below the packer; the initial flow period (IFP, 30-120 minutes) opens the tester valve and allows the formation to produce into the drill string, recording the flowing bottomhole pressure (FBHP); the initial shut-in period (ISIP, also called the first shut-in, 30-120 minutes) closes the tester valve and records the pressure buildup to the static reservoir pressure; additional flow periods (FP) and shut-ins (FSIP) may be conducted to improve the buildup quality and to collect additional fluid samples; the final shut-in period (FSIP) is the longest shut-in and provides the most reliable permeability and pressure data; conventional DST analysis uses Horner analysis of the pressure buildup data from the FSIP to determine kh (permeability-thickness product) and skin, and uses the static pressure from the ISIP to determine the formation pressure at the test depth.
• Wireline formation testing tools (MDT, RFT, FTWD) conduct openhole tests at a much smaller scale than drillstem tests, using a probe pressed against the borehole wall to draw fluid from the formation under controlled drawdown while measuring pressure continuously: single-probe MDT tests measure formation pressure at a point (the formation pressure test, FPT) in a few minutes each, building a pressure-depth profile that maps overpressure and underpressure zones and identifies fluid contacts from changes in the pressure gradient (gas gradient, oil gradient, and water gradient have characteristic slopes on a pressure-depth plot that allow fluid contacts to be located); multiprobe MDT tests use a source probe drawing fluid while a remote probe monitors the pressure response, providing a miniaturized interference test that measures horizontal permeability from the interference arrival time; vertical interference tests between probes at different depths in the same well measure vertical permeability (kV); the MDT is limited to lower-permeability, lower-rate tests than DSTs (maximum test rate typically less than 5 bbl/day at the surface equivalent, compared to thousands of bbl/day for DSTs) but provides much denser spatial sampling of reservoir pressure and fluid composition by testing at many depth points rapidly while the drill string is still in the hole.
• Fluid sampling during openhole tests is critically important for PVT characterization: formation fluid collected during a DST or wireline MDT provides samples of the reservoir fluid in its original state (composition, GOR, saturation pressure, viscosity, density, and fluid phase behavior) at reservoir conditions; the quality of openhole fluid samples is generally superior to produced samples collected later in the well's life, because the formation fluid closest to the wellbore is typically the least contaminated by mud filtrate invasion (the downhole sample tools collect deep enough into the formation to avoid or minimize the filtrate-invaded zone) and because the sample is collected before extended production has altered the near-wellbore fluid composition by depletion or compositional grading; the fluid sample is characterized in the laboratory by recombination PVT analysis (measuring the composition and properties of the gas and oil phases separately and combining them in the original GOR to reproduce the reservoir fluid), providing the fluid characterization data needed for tubing performance calculations, separator design, facilities sizing, and phase behavior modeling in reservoir simulation; in gas condensate systems, the retrograde condensate dropout behavior (the amount of liquid that forms from the gas as pressure drops below the dew point) is measured from the PVT sample and directly affects the production engineering design of gas handling facilities and compression systems.
• Openhole test interval selection determines which formations are evaluated and which are bypassed without data: in a well that has penetrated multiple potential reservoir units, the decision of which intervals to test is based on the log evaluation (gamma ray, resistivity, neutron-density crossplot) that identified the most promising hydrocarbon-bearing intervals, the time and cost constraints of the well (each DST requires rig time for running and retrieving the tool string, typically 24-72 hours per test including packer setting and retrieval), and the geological model for the reservoir architecture; selecting too many test intervals to maximize geological data collection may extend the well duration beyond the economic limit; selecting too few may miss important information about reservoir quality, connectivity, or pressure in a unit that was not obvious from logs alone; typical exploration wells test 1-3 intervals in a single openhole completion or in multiple cased-hole sidetracks from the same wellbore; appraisal wells may test 2-5 intervals to characterize the vertical variation in reservoir quality across the appraisal objective.
• Openhole test risks and complications include blowout during the flow period (if the formation pressure and productivity exceed the well control capacity of the test string and mud column system), stuck pipe (if the packer cannot be released after the test due to differential pressure locking or mechanical failure, requiring fishing operations that may require the drill string to be cut and the wellbore sidetracked), lost circulation (if the formation is fractured and the test fluid pressure exceeds the fracture gradient), and formation damage from the test itself (mud filtrate invasion during drilling, packer element contamination of the formation face, or mechanical compaction of the near-wellbore formation by the packer setting force); blowout risk is managed by careful pre-test pressure calculations (the expected shut-in surface pressure from a full-bore blowout must not exceed the rated working pressure of the test string and the BOP equipment), and by maintaining the well under control (keeping drill pipe shut-in capability at all times and never opening the tester valve without confirmed ability to shut it again); openhole test procedures have been significantly standardized by API RP 19G and by company-specific DST procedures that define the pre-test safety analysis, the tool string configuration requirements, and the pressure monitoring and shut-down criteria that govern safe openhole testing in different well environments.