What are the steps in conducting a well test offshore?

I. High-level purpose and value-chain context

Offshore well testing validates reservoir deliverability, fluids, and pressure behavior under controlled flow and shut-in, informing completion design, facility sizing, reserves classification, and commercial decisions while assuring HSE compliance.

• I.1 Purpose: quantify rates, pressures, productivity index, skin, permeability, boundaries; confirm fluid PVT and contaminants; verify sand/hydrate/wax risks; establish gas deliverability; set operating envelopes.
• I.2 Where it fits: after drilling/perforation or during completion (DST/EWT) and before tie-back or full production; interfaces with subsurface appraisal, surface processing/flaring, logistics, and regulatory reporting.
• I.3 Test modes: short cleanup and drawdown/build-up; drill stem test (DST) with downhole tools; extended well test (EWT) with surface separation and flaring or temporary export.

II. Step-by-step offshore well test process flow

II.A Planning and engineering

• II.A.1 Define objectives: data requirements (k, s, p*, J, AOF), fluid samples, sand/hydrates assessment, contamination tolerances; target rates/pressures and allowable flare volumes.
• II.A.2 Basis of design: expected reservoir/WHFP, GOR/WOR, H2S/CO2, solids; select test type (DST vs post-completion test vs EWT), duration, flow sequence, subsea vs platform configuration.
• II.A.3 HSE and regulatory: permits, flare/vent consents, SIMOPS plan, QRA, HAZID/HAZOP, SOS/Medivac, dropped-object and station-keeping envelopes; emergency shutdown (ESD) and disconnect logic.
• II.A.4 Mob/demob and logistics: vessel/rig deck layout, payload, crane charts; weather window; consumables (diesel, methanol/MEG, nitrogen, chemicals, burner heads), waste and sample shipment plans.

II.B Equipment preparation and integrity

• II.B.1 Rig-up: install and pressure-test downhole DST or completion test string; deploy subsea test tree (SSTT) and flowhead/well test tree; lay out surface package (chokes, separator, metering, burner/flare).
• II.B.2 Function/pressure tests: SIT of each component; high/low pressure tests; ESD loops; leak checks; verify chemical injection and seawater curtain; instrument/calibration checks.
• II.B.3 Barrier validation: confirm dual independent barriers; inflow/outflow tests; negative and positive tests as per well test program.

II.C Execution sequence (typical)

• II.C.1 Well access and inflow: perforate (if applicable) and displace to kill/underbalanced fluid as planned; set packer(s); run bottomhole gauges and samplers; verify SSTT connectivity.
• II.C.2 Initial cleanup flow (2–12 hours estimated): open tester valve on small choke; remove completion fluids; ramp chokes to target WHFP constraints; monitor returns for solids and emulsions.
• II.C.3 Shut-in #1 (PBU) (4–24 hours): close downhole tester valve (preferred) for high-fidelity pressure build-up; maintain surface package on stand-by; QC real-time gauge data if available.
• II.C.4 Main flow period(s) (8–24 hours each): step-rate to multiple stabilized rates within surface limits; hold each rate to pseudo-steady; acquire samples (separator and downhole).
• II.C.5 Rate-transient/deliverability: conduct multi-rate gas backpressure test or liquid flow-after-flow for J; optional isochronal/modified isochronal for gas with shut-ins between rates.
• II.C.6 Final shut-in (long PBU) (24–72 hours): capture late-time data for boundaries and k·h; verify tool memory and redundancy; retrieve bottomhole samples if programmed.
• II.C.7 Contingencies: hydrate/wax response, sand surge control, H2S souring protocol, ESD and emergency disconnect, weather standby; execute as per risk register.

II.D Demobilization and analysis

• II.D.1 Secure and bleed-down: close primary/secondary barriers; depressurize lines; flush with inhibited diesel/seawater; recover burner tips; waste segregation.
• II.D.2 Data and samples: download gauges; chain-of-custody for PVT bottles; field QC; preliminary PTA/deliverability calculations for on-scene decisions.
• II.D.3 Reporting: HSE, volumes flared, emissions, test log; integrate with petrophysics and PVT; recommendations for completion/stimulation and facility design.

III. Major equipment/components and functions

• III.1 Downhole DST/test string: packer(s), tester valve, circulation valve, gauge carriers (quartz), rupture discs, safety joints, samplers; enables controlled drawdown and shut-in at reservoir depth.
• III.2 Subsea package (subsea wells): SSTT with dual barriers, lubricator valve, retainer valve, quick-disconnect; landing string and umbilicals for hydraulic control and ESD.
• III.3 Surface well test tree/flowhead: master and wing valves, swivel, kill line, crossover to choke manifold; primary surface isolation and ESD integration.
• III.4 Choke manifold: fixed/adjustable chokes for rate/pressure control; dual trains for redundancy; rated for maximum WHFP.
• III.5 Data header/instrumentation: high-accuracy pressure/temperature transmitters, densitometer, sand probe; line pressure safety reliefs and PSV.
• III.6 Heater/heat exchanger: mitigate hydrates; maintain > hydrate equilibrium temperature margin at choke and separator.
• III.7 3-phase separator: bulk separation of oil/gas/water; level controls; anti-foam; internals for efficiency; optional test and production separators for cross-check.
• III.8 Metering: Coriolis/turbine meters, or multiphase meter; gas orifice/Coriolis; water cut meters; sampling systems for PVT and contaminants (H2S, CO2, mercaptans).
• III.9 Sand management: desander/sand trap, acoustic sand monitor, cyclones; safe discharge/containment.
• III.10 Burner/flare spread: burner boom with multi-nozzle heads, air-assist/pressure-assist; seawater curtain; ignition system; radiation monitoring; pilot gas or diesel assist.
• III.11 Chemical injection: methanol/MEG, corrosion inhibitor, demulsifier, defoamer, wax/asphaltene inhibitors; dosing pumps and tanks.
• III.12 Safety systems: ESD/PSD logic, HIPPS (if used), fire/gas detection, emergency quick disconnect; pressure reliefs and flare KO drum (if installed).

IV. Key performance drivers

• IV.1 Data quality: downhole gauge fidelity, wellbore storage minimized (downhole shut-ins), stabilized rate holds, accurate metering; rigorous time-depth correlation.
• IV.2 HSE and operability: robust ESD/disconnect, burner efficiency and radiation control, hydrate prevention, sand control, sour service management.
• IV.3 Emissions and flare management: minimize flared volumes while meeting test objectives; optimize burner stoichiometry and droplet size for >98% destruction efficiency; avoid black smoke.
• IV.4 Uptime: redundancy in critical paths (dual chokes, spare instruments, power); weather-resilient layout; swift choke/flow control.
• IV.5 Cost efficiency: tight critical path schedule, right-sized equipment, accurate rate forecasts to avoid re-mobilization; effective SIMOPS to reduce rig/vessel time.

V. Typical challenges and mitigation

• V.1 Hydrates: risk at chokes/lines in wet gas/condensate.
  • Mitigation: heating upstream of choke; continuous methanol/MEG dosing; insulation; maintain subcool margin; avoid long low-rate operation.
• V.2 High GOR and flare stability:
  • Mitigation: burner head selection, atomization air/steam, staged nozzles, diesel assist for ignition stability, radiation modeling and deck shielding.
• V.3 Sand production/surges:
  • Mitigation: conservative ramp-up, desander/sand trap, sand probes, rate limits, consider temporary downhole sand control for EWT.
• V.4 Wax/asphaltene precipitation:
  • Mitigation: heat maintenance, solvent/wax inhibitor injection, avoid sub-cooling; set rates to keep wall shear above deposition threshold.
• V.5 Sour fluids (H2S/CO2):
  • Mitigation: NACE-compliant metallurgy, scavengers, upgraded PPE and detection, exclusion zones, stricter ESD logic and evacuation plans.
• V.6 Wellbore storage and data smearing:
  • Mitigation: downhole shut-ins, steady-rate holds, large-bore gauges near perforations, minimize trapped gas in annulus.
• V.7 Weather/DP excursions:
  • Mitigation: real-time environmental monitoring, quick disconnect readiness, heave-compensated strings, conservative sea state limits.
• V.8 Regulatory flare constraints:
  • Mitigation: isochronal methods to reduce flare, staged testing, temporary export to bunkering where permitted, robust pre-permitting.

VI. Why this activity matters

• VI.1 Economic impact: reduces subsurface uncertainty (k·h, s, boundaries), enables accurate production forecasts and facility sizing, supports contingent-to-reserves maturation and investment decisions.
• VI.2 Operational readiness: validates completion strategy, flow assurance risks, sand/hydrates management, and safe operating envelopes prior to full-field development.
• VI.3 Regulatory and stakeholder assurance: demonstrates safe, compliant operations and environmental stewardship via minimized flaring and robust controls.

VII. Core formulas used in offshore well test interpretation

VII.A Liquid (oilfield units)

• VII.A.1 Radial Darcy flow:

  $$ q = \frac{0.00708\,k\,h}{\mu B}\,\frac{p_e - p_{wf}}{\ln\!\left(\frac{r_e}{r_w}\right) + s} $$

  q in bbl/d, k in mD, h in ft, µ in cP, B factor, pressures in psi, radii in ft.

• VII.A.2 Permeability from buildup (Horner):

  $$ k = \frac{162.6\,q\,\mu\,B}{m\,h} $$

  m is semilog slope (psi per log cycle), q in STB/d.

• VII.A.3 Skin from buildup:

  $$ s = 1.151\left[\frac{p^* - p_{wf}(0)}{m} - \log_{10}\!\left(\frac{k\,t_p}{\phi\,\mu\,c_t\,r_w^2}\right)\right] $$

  p* is Horner intercept (psi), t_p is flow time (hr), ? porosity, c_t total compressibility (psi?¹).

• VII.A.4 Horner time ratio:

  $$ H = \frac{t_p + \Delta t}{\Delta t} $$

• VII.A.5 Productivity index:

  $$ J = \frac{q}{p_r - p_{wf}} $$

VII.B Gas deliverability (backpressure method)

• VII.B.1 Non-Darcy deliverability:

  $$ q = C\left(p_r^2 - p_{wf}^2\right)^{n} $$

  Determine C and n from multi-rate data; AOF from extrapolation to p_wf ? 0.

• VII.B.2 Isochronal/modified isochronal: repeated equal-duration flow periods with intervening shut-ins to reduce flare while obtaining C and n.