What are the steps in conducting production logging?

I. High-level purpose and value-chain context

Production logging (PLT) determines how fluids enter or exit the wellbore along the completed interval under defined flow conditions. It supports production optimization, water/gas shutoff, wellwork targeting, allocation, and integrity diagnostics. It sits in the production operations and reservoir management segment of the upstream value chain, bridging subsurface characterization and day-to-day production control.

• I.1 Purpose: quantify phase holdup and interval-by-interval rates; identify water/gas entry, crossflow, behind-casing leaks, and completion performance.
• I.2 Typical scope: flowing and shut-in passes, multi-rate tests, depth correlation, and post-job interpretation to apportion flow by zone.
• I.3 Outcomes: zonal rates, water/gas breakthrough locations, guidance for zonal isolation, lift optimization, stimulation, and recompletion.

II. Step-by-step process flow

• II.1 Define objectives and constraints
  • II.1.1 Objectives: e.g., quantify water entry in a deviated producer; confirm crossflow under shut-in; validate zonal contribution after stimulation.
  • II.1.2 Constraints: temperature/pressure limits, deviation, completion hardware (slotted liner, screens, ICDs), artificial lift (gas lift, ESP), well access (e-line, slickline memory, tractor, coiled tubing), and H2S/CO2.
• II.2 Data gathering and pre-job analysis
  • II.2.1 Collect: well schematics, deviation survey, PVT, relative permeability, completion drawings, prior logs (CNL/GR/CCL, temperature, cement bond), production history, sand/wax/scale trends.
  • II.2.2 Model expected flow regime and holdup versus rate using drift-flux or mechanistic correlations (estimated) to set pass count, rate steps, and toolstring design.
• II.3 Program design and HSE planning
  • II.3.1 Select conveyance (e-line preferred; memory PLT via slickline or tractor for high deviation; coiled tubing if circulation or high drag anticipated).
  • II.3.2 Define sequence: stabilization period, baseline shut-in pass, flowing passes at 2–3 rates, stationary stations, leak/noise survey, final shut-in temperature.
  • II.3.3 Pressure control package, barriers, contingency (stuck tool, loss of containment, packer leak). Permits, SIMOPS, flare planning to minimize emissions.
• II.4 Well conditioning
  • II.4.1 Clean-up if needed (circulate debris, mitigate sand); stabilize at target rate(s); document wellhead and downhole P/T.
  • II.4.2 For ESP/gas lift: set operating points and lock out control changes during logging steps.
• II.5 Tool selection and QA/QC
  • II.5.1 Base sensors: pressure, temperature, CCL/GR; flow sensors per phase behavior (fullbore or micro spinner, array spinner for deviated/horizontal, capacitance/resistivity for water holdup, density/gradiomanometer, optical probes, noise).
  • II.5.2 Surface spin/response calibration; leak/pressure tests; centralization plan; confirm temp/pressure ratings.
• II.6 Rig-up and function tests
  • II.6.1 Install lubricator, wireline valve, grease head/BOPs; pressure test to MAWHP + safety margin.
  • II.6.2 Surface systems check, depth encoder, tension, telemetry. Verify fail-safe shears and fishneck profile.
• II.7 Depth correlation and baseline
  • II.7.1 Correlate depth using CCL/GR to known markers; set master depth reference and stretch corrections.
  • II.7.2 Record baseline shut-in temperature/pressure profile; identify thermal anomalies and integrity signals.
• II.8 Flowing passes
  • II.8.1 Continuous passes: low logging speed in verticals; slower and with array tools in deviated/horizontal to manage stratification.
  • II.8.2 Stationary measurements at perforation clusters and suspected zones to reduce spinner bias and improve holdup estimates.
  • II.8.3 Multi-rate: repeat passes at 2–3 stabilized rates to break non-uniqueness in holdup/velocity solutions.
• II.9 Integrity checks
  • II.9.1 Spectral noise, temperature fall-off, and pressure gradient surveys to locate leaks, crossflow, and behind-casing channels.
• II.10 Repeatability and QC
  • II.10.1 Up/down repeat passes for hysteresis and tool response drift; verify spinner linearity and threshold at zero-flow sections.
• II.11 Pull-out and demobilization
  • II.11.1 Recover toolstring, bleed-off and equalize, secure well, and demobilize pressure control equipment.
• II.12 Processing and interpretation
  • II.12.1 Apply depth shift, temperature corrections, spinner calibration, holdup inversion using selected multiphase model (estimated), regime maps, and slip corrections.
  • II.12.2 Balance inflow/outflow with surface rate; compute zonal phase rates with uncertainty; issue operational recommendations.

Key equations used during PLT interpretation

• II.E.1 Spinner velocity to mixture velocity:

  \( v_m = a\,(N - N_0) \) where \(v_m\) = mixture velocity, \(N\) = spinner rpm, \(N_0\) = threshold rpm, \(a\) = calibration slope (from surface/zero-flow calibration).

• II.E.2 Superficial velocities and cross-sectional area:

  \( j_k = \dfrac{q_k}{A} \), \( v_m = \sum j_k \), \( A = \dfrac{\pi}{4}\,(D_{ID}^2 - D_{tool}^2) \)

• II.E.3 Holdup and phase split (volumetric):

  \( v_m = \alpha_o v_o + \alpha_w v_w + \alpha_g v_g \), with \( \alpha_o + \alpha_w + \alpha_g = 1 \)

  Phase rates: \( q_k = \alpha_k\, v_k\, A \)

• II.E.4 Drift-flux (estimated) to correct slip, especially deviated/horizontal:

  \( v_{g} = C_0\,j_m + V_d + \alpha_g\,v_{slip} \), where \(C_0\) is distribution parameter, \(V_d\) drift velocity; parameters chosen per regime.

• II.E.5 Pressure gradient for fluid density check:

  \( \left(\dfrac{dP}{dz}\right) = \rho_m g + \dfrac{2f\rho_m v_m^2}{D_{hyd}} + \rho_m \dfrac{dv_m}{dt}\, \) (steady-state usually neglects acceleration term).

• II.E.6 Zonal material balance along completion:

  \( q_{t}(z_{i+1}) = q_{t}(z_{i}) + \sum q_{k,i}^{in} - \sum q_{k,i}^{out} \) with cumulative step-changes interpreted as interval contributions.

III. Major equipment/components and functions

• III.1 Conveyance
  • III.1.1 Electric line: real-time data; preferred for most wells.
  • III.1.2 Slickline memory PLT: when e-line not feasible; requires stable conditions and robust planning.
  • III.1.3 Coiled tubing: adds circulation and push; for high deviation, obstructions, or to convey below tight restrictions.
  • III.1.4 Downhole tractor: for highly deviated/horizontal wells on e-line.
• III.2 Toolstring (typical from top to bottom)
  • III.2.1 Telemetry/battery head and releases; knuckle joints; centralizers.
  • III.2.2 Gamma ray and CCL for depth correlation.
  • III.2.3 Quartz pressure and fast-response temperature sensors.
  • III.2.4 Flow sensors: fullbore or micro spinner; array spinner for stratified/segregated flow.
  • III.2.5 Phase holdup sensors: capacitance/resistivity (water holdup), optical (gas/oil identification), density/gradiomanometer (mixture density).
  • III.2.6 Acoustic/noise tool for leak detection and crossflow.
  • III.2.7 Caliper or imaging sub (optional) for borehole geometry.
• III.3 Surface pressure control
  • III.3.1 Lubricator, wireline valve, grease injection head, BOPs, quick test sub; pressure-tested to job MAWHP.
  • III.3.2 Surface acquisition, depth measurement, and tension systems.
• III.4 Ancillaries
  • III.4.1 Flow loop for spinner calibration; centralizers/rollers; sinker bars; debris baskets; magnets; fishing necks.
  • III.4.2 Temporary surface metering (if needed) to validate rate steps and reduce uncertainty.

IV. Key performance drivers

• IV.1 Data quality and uncertainty
  • IV.1.1 Depth match tolerance = 0.5 ft; spinner linearity and threshold confirmed in situ; repeatability between passes within 5–10% of rate.
  • IV.1.2 Adequate rate separation between multi-rate steps (= 15–25%) to resolve holdup non-uniqueness.
• IV.2 Operational efficiency and cost
  • IV.2.1 Well conditioning to minimize stabilization time; optimized pass speeds; minimize rig-up/rig-down time via modular pressure control.
• IV.3 Safety and integrity
  • IV.3.1 Strict barrier management; pressure tests; H2S/CO2 monitoring; adherence to SIMOPS controls.
  • IV.3.2 Sand management and debris mitigation to protect tool and wellhead equipment.
• IV.4 Emissions management
  • IV.4.1 Limit flaring by using existing process capacity or temporary separation; consolidate rate steps; avoid unnecessary shut-ins.

V. Typical challenges and mitigation

• V.1 Multiphase flow complexity
  • V.1.1 Stratified/slug/annular flow causes spinner bias. Mitigate with array spinners, stationary stations, lower pass speeds, and multi-rate testing.
  • V.1.2 High GOR or foamy oil reduces holdup sensor fidelity. Combine density, capacitance, and optical; calibrate with PVT and pressure gradient.
• V.2 Well geometry and deviation
  • V.2.1 Eccentering and tool sticking. Use centralizers/rollers and conveyance aids; consider tractors or coiled tubing for horizontals.
• V.3 Completion complexities
  • V.3.1 Screens/ICDs and limited entry reduce local velocity signals. Use stationary profiling and pressure/temperature diagnostics; consider packer-isolated mini-tests if allowed.
• V.4 Surface rate uncertainty
  • V.4.1 Inaccurate surface allocation skews zonal rates. Deploy temporary metering or back-calculate total rate using downhole mixture velocity and density.
• V.5 Harsh conditions
  • V.5.1 Sand, scale, wax cause spinner drag and tool damage. Pre-job cleanout and chemical treatment; use protected micro-spinners and debris subs.
  • V.5.2 High temperature/pressure exceed ratings. Choose high-spec sensors; reduce exposure time; consider memory tools with higher ratings.
• V.6 Artificial lift interference
  • V.6.1 Gas lift cycling or ESP turbulence distorts measurements. Stabilize lift parameters; log across stable load points; increase stationary time.

VI. Why this activity matters

• VI.1 Directs high-ROI interventions: precise water/gas shutoff, targeted reperf/stimulation, lift optimization—reducing water handling and increasing net oil.
• VI.2 Improves reserves and allocation accuracy by constraining zonal contributions and validating reservoir models.
• VI.3 Enhances integrity management by locating leaks and crossflow, reducing unplanned downtime and safety exposure.
• VI.4 Optimizes OPEX and emissions by minimizing excess produced water/gas and unnecessary flaring during diagnostics.