What are the duties of a well test supervisor on offshore rigs?

Well Test Supervisor (Offshore) — Duties and Role Overview

Leads the planning, safe execution, and on-site optimization of surface and downhole well testing on offshore rigs, ensuring data quality, flow assurance, compliance, and protection of people, assets, and the environment.

I. Core Responsibilities

• I.1 Planning and Readiness — Review test program, P&IDs, rig-up drawings, equipment lists, and operating envelopes; lead hazard reviews; verify pressure ratings and barriers; align test objectives with subsurface requirements.
• I.2 Mobilization and Rig-Up — Direct safe deck layout; supervise rig-up of the test spread (test tree/flowhead, ESD panels, choke manifold, separator, burner/flare, sand management, sampling, MPFM); conduct function tests and pressure tests to specified limits.
• I.3 Barrier and Well Control Assurance — Confirm dual-barrier policy; validate downhole test string components and surface safety systems; integrate test ESD with rig systems; maintain kill line readiness and pressure monitoring.
• I.4 Coordination of Downhole Operations — Interface on perforating/DST operations, slickline/wireline valve operations, gauge placement and timing; ensure clean-up, drawdown, multi-rate, and shut-in periods follow the approved sequence.
• I.5 Test Execution and Optimization — Manage choke schedule, separator pressures/levels, and flow routing; stabilize flow, control carryover/foaming; adjust for slugging; enforce erosional velocity and burner capacity limits.
• I.6 Data Quality and Sampling — Oversee data acquisition (pressures, temperatures, rates, GOR, water cut, sand rate); validate gauge clocks; ensure representative PVT and water samples with chain-of-custody; perform on-site QA/QC.
• I.7 Safety, HSE, and Compliance — Lead toolbox talks and permit-to-work; manage H2S/LEL risks, ignition sources, hot zones, and gas dispersion; verify relief/vent paths; record and report flare volumes and emissions per regulation.
• I.8 Troubleshooting and Contingency — Diagnose emulsion/hydrate/sand issues; mitigate with heat, chemicals, or choke strategy; respond to leaks, ESD trips, or abnormal pressures per emergency procedures; exercise stop-work authority.
• I.9 Reporting and Handover — Issue daily reports, real-time decision logs, test summaries, lessons learned; deliver end-of-well test datasets (pressure files, rate histories, sample manifests) to reservoir and production engineering.
• I.10 Demobilization — Supervise rig-down, decontamination, preservation; reconcile inventory; close permits; finalize closeout report.
• I.11 Crew Leadership and Competency — Lead well test operators and lab techs; coach junior staff; verify competencies; enforce safe work practices and housekeeping.

II. Required Skills and Physical Demands

• II.1 Technical Skills — Surface and downhole well testing, DST string components, pressure control and barrier policy, multiphase separation, flow metering, PVT/sampling, pressure transient basics (drawdown/buildup), choke management, sand/hydrate/emulsion control, H2S management, ESD/ESV logic, flare/burner operations, basic nodal analysis.
• II.2 Soft Skills — Leadership, clear communication, situational awareness, rapid risk-based decision-making, conflict resolution, meticulous record keeping.
• II.3 Certifications (typical) — Offshore survival and sea survival, supervisor-level well control (well intervention/pressure control), H2S awareness/use of escape sets, confined space/working at height, lifting operations awareness.
• II.4 Physical Demands — Offshore 12-hour shifts (day/night), climbing and work at height, manual handling of loads (~25–35 kg with aids), heat/cold, noise (>85 dB), respirator/SCBA use when required.

III. Typical Tools, Software, and Equipment Used

• III.1 Downhole/DST — Test packers, valves, circulating/reciprocal valves, pressure/temperature gauges (memory or real-time), debris/sand control subs, contingency shear-release mechanisms.
• III.2 Surface Test Package — Test tree/flowhead with ESD, choke manifold (adjustable and bean chokes), heater/line heaters, 3-phase separator(s), multiphase flow meter, surge tanks, sand trap/cyclone/desander, filtration/coalescers, burner head/flare boom, relief/PSV, chemical injection (methanol/MEG, demulsifiers, antifoam), portable lab.
• III.3 Measurement and Controls — Pressure/temperature transmitters, level controllers, Coriolis/turbine meters, water cut and gas analyzers, data acquisition system, SCADA links, ESD/HIPPS interfaces, gas detection and H2S monitors.
• III.4 Software — Surface data acquisition/trending, choke and separator sizing calculators, pressure transient analysis suite, basic nodal analysis, emissions/flare accounting spreadsheets, digital permit-to-work.
• III.5 Safety/Response — SCBA, fire and deluge interfaces, portable gas monitors, emergency lighting/communications.

IV. Work Environment

• IV.1 Location — Offshore jack-ups, semisubs, or drillships; operations may involve HP/HT or sour service.
• IV.2 Schedule — 12-hour shifts; common rotations 14/14, 21/21, or 28/28; night operations frequent during test sequences.
• IV.3 Campaign Durations — Short DSTs: ~2–10 days per well; extended well tests: ~30–90 days (estimated).
• IV.4 Travel — Helicopter or crew boat; pre/post-mob briefings at shore base.

V. Reporting Lines and Cross-Functional Interfaces

• V.1 Reporting To — Wellsite representative for the operating company (drilling/completions supervisor) on the rig; functional line to an onshore testing superintendent/engineer.
• V.2 Direct Reports — Senior well test operator(s), well test operators/assistants, sampling/lab technician.
• V.3 Key Interfaces — Drilling and completions teams, subsea/tree engineers, wireline/slickline and perforating crews, fluids/mud engineers, production chemistry, metering, HSE, marine/logistics, rig mechanical/electrical teams.

VI. Career Ladder

• VI.1 Next-Step Roles — Senior Well Test Supervisor, Well Test Superintendent, Completions Supervisor (testing focus), Production Testing Specialist.
• VI.2 What’s Needed to Move Up — Proven safe delivery of multiple offshore DST/EWT campaigns, HP/HT and sour service exposure, strong data quality and interpretation acumen, leadership/crew development, stakeholder management, audit-ready documentation.
• VI.3 Development — Advanced well test interpretation, flow assurance (hydrates, emulsions, wax/asphaltene), multiphase metering uncertainty, incident command/emergency response leadership.

Deliverables & Interfaces

• Operational Deliverables — Daily well test report, real-time rate/pressure trends, choke schedule, safety minutes, barrier verification records, pressure test certificates, flare/emissions logs.
• Technical Deliverables — Cleaned pressure files (downhole gauges), flow period/buildup timing table, validated rate allocations, PVT sample manifests, preliminary PI/skin estimates, end-of-test summary.
• Handoffs — Data packages to reservoir and production engineering; emissions and hydrocarbon accounting to regulatory/reporting; lessons learned to planning/engineering; equipment status to maintenance/logistics.

Toolchain Snapshot

• Surface — Test tree/flowhead with ESD, choke manifold, heater, 3-phase separator, MPFM, sand management, burner/flare, surge tanks.
• Downhole — DST packers/valves, memory/telemetry gauges.
• Measurement/Control — Pressure/temperature transmitters, flow meters, gas and H2S detection, data acquisition, ESD/HIPPS interface.
• Software — Data logging/trending, separator and choke calculations, pressure transient analysis, nodal analysis, emissions accounting.

Progression Trigger

Typically promoted after delivering ~8–12 offshore well tests (DST/EWT) including 2–3 complex HP/HT or sour jobs, with zero major incidents, documented data quality, and supervisor-level well control plus current offshore survival and H2S certifications (estimated).

VII. Key Equations and Quick Checks (on shift)

• VII.1 Productivity Index — \( J = \dfrac{q}{p_\mathrm{res} - p_\mathrm{wf}} \). Quick check of well deliverability during stabilized flow.
• VII.2 Radial Flow with Skin — \( q = \dfrac{2 \pi k h}{\mu B} \cdot \dfrac{(p_e - p_\mathrm{wf})}{\ln\!\left(\dfrac{r_e}{r_w}\right) + s} \). Useful for estimating expected rates vs. drawdown (estimated field check).
• VII.3 Buildup (Horner) Time — \( t_H = \dfrac{t_p + \Delta t}{\Delta t} \); semilog derivative stabilization indicates boundary/skin effects.
• VII.4 Permeability (semilog method, field units) — \( k \approx \dfrac{162.6\, q\, \mu\, B}{m\, h} \), where m is the semilog slope in psi/cycle (estimated quick-look).
• VII.5 Erosional Velocity Limit — \( v_e = \dfrac{C}{\sqrt{\rho_\mathrm{mix}}} \) with C per company standard (e.g., 100–150 in customary units). Use to cap allowable line velocities.
• VII.6 Liquid Choke Sizing (incompressible, simplified) — \( q \approx C_v \sqrt{\dfrac{\Delta P}{SG}} \). For preliminary choke setting and rate steps.
• VII.7 Gas Critical (Choked) Flow through Orifice (simplified) — \( \dot{m} \approx C_d A P_0 \sqrt{\dfrac{\gamma}{R T_0}} \left(\dfrac{2}{\gamma+1}\right)^{\tfrac{\gamma+1}{2(\gamma-1)}} \). Checks burner and downstream capacity (estimated).
• VII.8 Separator Retention Time — \( t = \dfrac{V}{Q} \). Helps verify liquid retention time vs. separation targets during rate ramps.
• VII.9 Burner Heat Release — \( \dot{Q} = \dot{m} \cdot HHV \). Ensure within burner rating and safety envelope.