Stop the bleed.
Wellhead to pipeline.

ROP drop ~40% on the 8¾″ section at ~9,200 ft TVD/MD in the Utica is a classic mid-intermediate / upper-lateral transition problem. Treat it as a real-time drilling-efficiency and well-control risk until proven otherwise. Do not keep pushing the same parameters hoping it “comes back.”

Most likely causes ranked for Utica 8¾″ at this depth

1. Bit dulling / cutter damage or balling (PDC most common): primary suspect. Utica carbonates/shales + any abrasive stringers or pyrite chew cutters fast; balling on sticky clay intervals kills ROP hard.
2. Weight-on-bit (WOB) / differential sticking or poor weight transfer: torque/drag rising, buckling in the curve or high-angle section, or insufficient WOB transmitted to the bit.
3. Hydraulics / ECD / hole cleaning degradation: cuttings bed building, annular velocity too low, or ECD climbing and packing off. At 9,200 ft in Utica this is frequent when flow is constrained or mud weight has been raised for pore-pressure.
4. Formation change: entering denser Point Pleasant / lower Utica limestone stringers, higher UCS, or a natural fracture/fault zone that reduces cutter efficiency.
5. Bottom-hole assembly (BHA) / motor or RSS issues: motor stall, bearing wear, bent housing walk, or RSS toolface/power drop.
6. Mud property shift: solids climb, PV/YP out of window, lubricity loss, or swab/surge from poor rheology.
7. Secondary: bit balling from insufficient HSI, whirl/vibration (lateral or stick-slip), or undergauge stabilizers.

What to check first priority order: do these on the next stand or immediately

1. Pull a sample of the last 30 to 60 ft of cuttings and inspect the bit (if tripping is already planned or ROP stays dead)
   • Look for worn/chipped cutters, lost cutters, ring-out, balling (clay packed in junk slots), undergauge.
   • Utica nuance: pyrite and hard stringers produce distinctive cutter spalling; sticky zones ball fast if HSI < 2 to 3 hp/in².
2. Real-time surface and downhole parameters (right now)
   • WOB actual vs. surface, differential pressure across motor, torque, RPM, MSE (mechanical specific energy).
   • If MSE has spiked 2× while ROP fell 40%, you are grinding, not drilling.
   • Standpipe pressure trend: rising SPP at constant flow = packing off or bit nozzle plugging.
   • Hookload and pickup/slack-off weights for drag.
3. Hydraulics and hole cleaning
   • Confirm flow rate, annular velocity in the 8¾″ × drill-pipe annulus (target typically ≥ 150 to 180 ft/min for Utica intermediate; calculate with your exact DP/HWDP OD).
   • ECD from PWD vs. calculated: if ECD is climbing while ROP dies, clean the hole before adding weight.
   • Mud check: MW, PV, YP, 6-rpm reading, low-gravity solids, MBT. Utica nuance: solids creep and loss of inhibition quickly kill ROP and raise ECD.
4. Vibration and dynamics
   • Stick-slip, whirl, or axial vibration flags from the MWD/LWD. High stick-slip at this depth with a motor often means the bit is hanging up on a hard streak or the motor is underperforming.
5. Survey and trajectory
   • Dogleg severity and inclination: if you just built or are holding high angle, weight transfer suffers. Check for local doglegs that buckle the string.

Immediate field actions step-by-step

1. Record a full parameter snapshot (WOB, RPM, flow, SPP, torque, ROP, MSE, ECD, vibration).
2. Work the pipe: short trip or wipe the hole 1 to 2 stands, circulate bottoms-up, check for fill and cuttings volume/size/shape.
3. Adjust one variable at a time:
   • Increase HSI if nozzles allow (check total flow area).
   • Optimize WOB/RPM for the bit (often higher RPM, moderate WOB on PDC in Utica shale; reverse if hard stringer).
   • If motor, confirm differential pressure is in the sweet spot (not stalled, not free-wheeling).
4. If no response in 30 to 60 min of on-bottom time, plan a short trip to inspect the bit/BHA rather than drilling a long underperforming interval.
5. Update the kill sheet and MAASP: any packing off or ECD spike is a well-control precursor at this depth.

Quick diagnostic formulas / checks

Utica-specific nuances

• Pore pressure and fracture gradient windows can be tight; do not chase ROP by overloading ECD.
• Lateral or high-angle 8¾″ sections suffer cuttings beds that look like “formation change.”
• Winter or long laterals amplify torque/drag and weight-transfer problems.
• If you are near a known hard streak or fault from offset wells, expect the drop and have a backup bit/BHA staged.

Controls while troubleshooting: Maintain well control (API RP 53 / company well-control manual), continuous monitoring for pack-off/kick indicators, and a current JSA for any short trip or bit change. No shortcuts on BOP tests or flow checks.

Fix the root (usually bit state + hole cleaning + weight transfer) and ROP often recovers a large fraction of the loss. If it does not, you are in a new rock strength regime and need a different bit/BHA design for the remaining footage.

Mission locked in. Get the parameters and cuttings in front of you first, then decide trip vs. parameter tweak.

PHMSA Reporting: Class 1 Pipeline Leak, 5 bbl Condensate, No Waterway Impact

Direct answer

For a 5 bbl condensate release on a Class 1 liquid pipeline segment with no waterway impact, you generally do not owe PHMSA an accident report under 49 CFR 195.50 if all of the following are true:

• Unintentional release is under 5 barrels (your volume is exactly 5 bbl: treat this as a threshold edge case; confirm measured/estimated volume carefully),
• No explosion or fire resulting from the release,
• No death or personal injury necessitating hospitalization,
• Property damage (including cleanup/recovery, commodity loss, and operator/third-party damage) is ≤ $50,000 (current Part 195 property-damage threshold; verify the figure in force on the incident date),
• Release did not result in pollution of any water of the United States or other environmentally sensitive area as defined for reporting.

If volume is confirmed at or above 5 bbl, or cleanup/commodity/property damage exceeds the dollar threshold, or any injury/fire/explosion/water impact exists, you owe PHMSA a Part 195 accident report.

Nuance: “5 bbl” is the regulatory line. Field estimates that round to 5.0 can flip the duty. Err on the side of documenting the calculation (tank gauge, meter, vacuum truck tickets, residual in ditch). If true volume is ≥ 5 bbl, report.

Step-by-step what you owe and what you do

Step 1. Classify the asset and commodity

• Confirm it is a hazardous liquid pipeline under 49 CFR Part 195 (condensate typically is).
• Confirm Class 1 location (population density / dwelling count per Part 195 class definition). Class affects design/ops, not a free pass on accident reporting; reporting is driven by 195.50 / 195.52 / 195.54 criteria, not class alone.
• Confirm product = condensate (API gravity, H₂S, flash point) for spill response and SDS, and for whether any state “oil” definitions add parallel duties.

Step 2. Quantify the release (this decides PHMSA reportability)

Measure or engineer a defensible volume:

• Gross release from pipe/equipment
• Minus recovered product (if your company procedure allows net vs. gross: PHMSA accident criteria use release quantity; do not “net down” below reportability without a written, auditable basis)
• Include product in soil, on ROW, in secondary containment if it left the pipe unintentionally

Decision gate:

Your scenario: 5 bbl, no waterway.

• If volume is exactly 5.0 bbl → reportable under the ≥5 bbl criterion.
• If later refined to 4.x bbl and no other triggers → typically not PHMSA-accident-reportable, but keep the file as if you will be asked.

Nuance: Telephonic notice under 195.52 is a separate, narrower duty (e.g., certain severe outcomes, or criteria in the current rule text). A small Class 1 condensate drip with no death, injury, fire, or significant impact often does not require NRC/PHMSA telephonic notice, but always check the current 195.52 list against your facts before deciding “no call.”

Step 3. Telephonic / NRC notification (195.52)

Evaluate immediately against current 49 CFR 195.52 (summary of the usual severity triggers: confirm verbatim in the official CFR on the day of the event):

• Explosion or fire from the release
• Death or injury requiring hospitalization
• Event is significant in the operator’s judgment
• Other listed conditions (including certain liquid releases as specified in the rule)

For a routine 5 bbl Class 1 condensate leak, no fire, no injury, no waterway:

• NRC telephonic notice is often not required if no 195.52 trigger is met.
• If any doubt on volume, migration toward a ditch that could reach a water of the U.S., or public impact → notify NRC and document the call (NRC report number).

Nuance: State agencies and the NRC path are still used when oil hits water or when state rules say so. “No waterway impact” must mean verified, not “we didn’t look.”

Step 4. Written PHMSA accident report (195.54) if reportable

If 195.50 is met (including ≥ 5 barrels unintentional release):

1. Submit the hazardous liquid accident report in the PHMSA Portal (Form PHMSA F 7000-1 or successor)
2. Timing: per 195.54, typically within 30 days of discovery of the accident (confirm current text for any update or supplemental rules)
3. Supplements: file updates when final volume, cause, or costs change
4. Retain supporting package: leak location (lat/long, MP), pipe specs, pressure, discovery time, shutdown/isolate times, repair method, metallurgy/NDE if failure investigation, volume calc, photos, cleanup costs, commodity value

Cause fields: be accurate (corrosion, third-party damage, equipment, incorrect operation, material/weld, etc.). This feeds national trends and your own IMP.

Step 5. What you still “owe” even if PHMSA accident report is NOT required

PHMSA silence ≠ no obligations.

A. Operator documentation (always)

• Incident / near-miss / spill log
• Volume basis and sketch of affected ROW
• Pressure/flow SCADA at discovery
• Valve close times / isolation
• Repair (clamp, cut-out, weld) per Part 195 repair and welding quals
• Return-to-service pressure test or alternative if required by procedure/IM
• ROW remediation and waste manifests

B. Integrity Management / 195.452 (if HCA or could affect HCA)
Class 1 does not equal “not HCA.” Check whether the segment could affect a High Consequence Area. Leak may trigger:

• Immediate repair conditions evaluation
• Dig list / anomaly correlation if ILI-related
• Lessons learned into IMP

C. Part 195 operations & maintenance

• Patrol/leak survey effectiveness review if discovery was delayed
• CP/reads if corrosion-related
• Procedure update if human factors

D. Environmental (federal/state): condensate is often regulated as oil/petroleum
Even with no waterway impact:

• SPCC (40 CFR 112) if applicable facility: internal spill report, potentially amend SPCC if reportable oil discharge criteria met (navigable water sheen standard is different from PHMSA; land-only may still need company SPCC documentation)
• State oil & gas / environmental agency spill notification thresholds (often stricter than 5 bbl: many states want notice at 1 bbl or “any” to water, and sometimes any release above a few gallons on land)
• Waste characterization (crude condensate, absorbents, soil): RCRA/state solid waste as applicable
• Stormwater / permit conditions if on a permitted pad

E. Safety / OSHA

• If employees exposed to vapors (benzene in condensate), document IH/exposure and LOTO/hot work if repair required
• Injury → OSHA recordkeeping separate from PHMSA

F. DOT/PHMSA state partner
Many states are certified partners. State pipeline safety program may require parallel incident notice even when federal form is/isn’t due. Check the state commission pipeline safety rules for the state where the milepost sits.

Step 6. Cost / property-damage trap (why “5 bbl no water” still becomes reportable)

PHMSA property damage includes (conceptually):

• Value of lost commodity
• Cost of cleanup and recovery
• Operator and third-party property damage
• Cost of repair (sometimes debated in practice: follow current PHMSA instructions on Form 7000-1)

Worked example (illustrative):

If total exceeds the Part 195 dollar threshold, you owe the PHMSA accident report even if volume were under 5 bbl.

Nuance: Cheap “bucket and pad” vs. full soil cut can decide reportability. Track costs in the incident file from hour one.

Step 7. Practical reporting decision tree for this event

For stated facts (5 bbl): treat as ≥ 5 bbl → PHMSA written accident report owed, unless volume is revised below 5 with engineering basis. Telephonic only if 195.52 triggers appear.

What to file / record checklist

If reportable to PHMSA:

• PHMSA Portal account / operator ID
• F 7000-1 within regulatory deadline
• NRC number if any telephonic made
• Supplemental F 7000-1 when costs/cause finalized

Always:

• Internal incident report with timeline (SnapCharT-style if you later do RCA)
• Volume calculation sheet
• Maps: class location, HCA could-affect, waterways within buffer
• Repair documentation / welding procedures / NDE
• Environmental: soil sample results, disposal manifests
• Cost ledger (for threshold and insurance)
• Notifications log (time, name, agency, reference #)
• Management of change / procedure fix if ops-caused

Controls & compliance filter

• Engineering: isolation valves, leak detection sensitivity, containment at valves/launchers
• Administrative: spill reporting matrix (PHMSA + state + NRC + internal) posted in control room; 30-day calendar hold for F 7000-1
• PPE / response: condensate flammability: bonding/grounding, gas testing, FR clothing (NFPA 2112), respiratory if BTEX warrants
• References to keep on the desk:
  • 49 CFR 195.50 Accident reporting criteria
  • 49 CFR 195.52 Immediate notice
  • 49 CFR 195.54 Written accident reports
  • 49 CFR 195.452 IMP (if applicable)
  • 49 CFR 195.402 O&M procedural manual
  • PHMSA Hazardous Liquid Accident Report instructions (F 7000-1)
  • 40 CFR 112 SPCC (facility-dependent)
  • State pipeline safety and environmental spill rules

ROI / risk angle why get this right

• Late or missed PHMSA report → civil penalties (per day/per violation magnitudes are material), consent orders, and inspection focus.
• Over-reporting a non-event is cheaper than under-reporting a ≥5 bbl release.
• Clean volume and cost files protect you in audits and insurance recovery.
• Single 5 bbl leak that should have been reported and wasn’t can cost more in penalties/reputation than the cleanup.

Bottom line commander’s cut

1. Verify volume: at 5 bbl, plan on PHMSA written accident report (195.54 / F 7000-1) unless you can defend < 5 bbl and no other 195.50 triggers.
2. Telephonic 195.52 / NRC: only if severity criteria met; your stated facts often no, but re-check rule text and water migration.
3. Still owe full internal spill file, repair per Part 195, state/environmental checks, SPCC/company matrix, and IMP touch if could-affect HCA.
4. Add cleanup + commodity + damage dollars: they alone can force a PHMSA report.

Mission locked in. Measure twice, report once, keep the packet audit-ready.

Overnight Production Drop Diagnostic Protocol: Pad 7 (Ohio)

Asset: Pad 7, Ohio (Utica / Point Pleasant or equivalent wet-gas / condensate play)
Trigger event: ~18% overnight production decline with no planned shut-in

Purpose

Provide a disciplined, first-response diagnostic sequence so field operations can isolate the root of an unplanned ~18% production loss on Pad 7 before escalating to engineering. Goal: restore safe production, protect wellbore and surface integrity, document facts for RCA, and avoid unnecessary well interventions or false engineering call-outs.

Scope

Applies to all Pad 7 wells, shared surface facilities (separators, heaters, meters, manifolds, sales/line takeaway), artificial lift systems (ESP, gas lift, rod pump, plunger, or hybrid), SCADA/RTU, and third-party midstream interconnects in Ohio. Covers gas, oil/condensate, and water legs. Does not authorize well kill, major workover, or line pigging without engineering/TOC concurrence.

Responsibilities

• Lease Operator / Pumper: Execute Level 0 to 1 checks within first 60 to 90 minutes; log all readings; stop work on any H₂S, LEL, or pressure integrity red flag.
• Pad/Facility Operator: Verify separator, dump valves, meters, and shared header; coordinate multi-well isolation if needed.
• Artificial Lift Tech (if on call): Confirm ESP/VSD, gas-lift injection, rod-pump, or plunger status.
• Control Room / SCADA Tech: Pull trends, alarms, and freeze frames; export raw data package.
• Production Supervisor: Decide escalate vs. local restore; notify midstream if sales pressure/volume issue.
• Engineering (Reservoir / Production / Facilities): Engage only after Ops data package is complete unless well control, environmental release, or safety threshold is crossed.
• EHS: Activate if spill, venting beyond permit, or H₂S ≥ 10 ppm.

Nuance (Ohio): Many pads share a common sales header and third-party compressor/station. An 18% pad-level drop often sits in takeaway, meter, or one high-rate well, not every reservoir simultaneously. Confirm whether the 18% is pad total, per-well, oil only, gas only, or BOE.

PPE

• Hard hat (ANSI Z89.1)
• Safety glasses with side shields (ANSI Z87.1)
• FR clothing (NFPA 2112)
• Steel-toe boots (ASTM F2413)
• Gas detection: LEL / O₂ / H₂S / CO (action: H₂S 10 ppm, LEL 10%)
• Hearing protection if ≥ 85 dB (OSHA 1910.95)
• Gloves appropriate to fluids (Nitrile / chemical-resistant); face shield for sample points
• Fall protection if accessing elevated separator/walkways (OSHA 1926.501)
• NORM/TENORM awareness on filter socks and scale (Ohio scrap/waste rules)

Immediate Context & Decision Rules

Treat as abnormal until proven otherwise.
18% overnight with no planned shut-in is not normal decline.

Nuance: Overnight drops frequently track: (1) midstream suction pressure spike or station recycle, (2) separator dump/level failure and meter bypass, (3) ESP undervoltage/VSD trip, (4) gas-lift compressor or injection manifold issue, (5) hydrate/paraffin at choke or buried flowline, (6) SCADA scaling/totalizer error (false “decline”), (7) accidental partial valve closure after night ops.

Procedure: Diagnostic Order of Battle

Phase 0: Stabilize & Define the Loss (0 to 15 minutes)

1. Confirm the number is real
   • Compare last good stable day vs. last 24 h and last 6 to 8 h overnight window.
   • Split by phase: gas MCFD, oil/condensate BPD, water BPD, and BOE.
   • Check whether decline is pad total or dominated by 1 to 2 wells.

   Nuance: If oil down 18% but gas flat (or opposite), suspect separator dump, liquid meter, or emulsion, not reservoir.

2. Verify no planned or stealth shut-in
   • Check overnight work orders, midstream notices, SWD constraints, flare/vent permits, and any “soft” choke changes.
   • Call night pumper / control room: any ESD, SDV close, station outage, or pigging?
3. Safety sweep
   • Walk pad upwind: smells, hissing, ice (hydrate), oil staining, tank overflows, VRU status.
   • Read multi-gas at wellheads, separator, and thief hatches.
4. SCADA snapshot (do not reset alarms yet)
   • Freeze: WHP, CHP/THP, flowline pressure, separator pressure, differential pressure on meters, ESP amps/Hz/PI, gas-lift injection rate/pressure, tank levels, sales pressure, SDV positions.
   • Export 72-hour trends at 1 to 5 minute density if available.

Phase 1: Well-Level Checks (First Physical Priority)

Perform per well, starting with highest historical producers (they drive pad %).

1. Wellhead & tree
   • Master, wing, swab, choke position vs. last set point (count turns / bean size).
   • Verify SDV / ESD valve open and supply gas/air pressure healthy.
   • Note WHP and temperature. Cold + pressure up → possible hydrate. Hot ESP well + pressure down → possible lift failure or open path to low pressure.
2. Tubing vs. casing pressures
   • Record THP/WHP and CHP.
   • Gas lift: casing pressure should reflect injection design. Collapse of CHP → injection loss or hole in tubing.
   • Packer / annular integrity: unexpected CHP rise on non-GL wells → communication or gas migration: flag engineering.
3. Flowline from well to header
   • Surface pressure at well wing vs. header inlet.
   • Large ΔP → restriction (hydrate, scale, sand, partially closed valve, crushed line).
   • Feel/thermal gun on jumpers; listen for sand.
4. Choke & bean
   • Confirm actual bean matches SCADA. Night crews sometimes leave choke partially closed after sampling or build-up.
5. Downhole / lift quick status (see Phase 4 for depth)
   • ESP: running? VSD fault code? Amps vs. baseline?
   • Rod pump: unit running, polished rod load unusual, stuffing box leak?
   • Plunger: arrival frequency, arrival velocity, lubricant.
   • Natural flow: is well loaded (high WHP, low flow)?
6. Well test / test separator routing
   • Confirm wells not accidentally left on test loop or bypass with meter offline.

Nuance (Utica/Ohio): Liquids-rich wells load up fast if line pressure rises 50 to 100 psi overnight. A midstream suction change can look like “reservoir decline” on every well at once: differentiate by simultaneous WHP increase across the pad.

Phase 2: Separator & Surface Process Checks

Shared pad separators often explain “everyone is down.”

1. Inlet pressure & temperature
   • Compare to yesterday same hour.
   • High inlet + low sales flow → dump stuck, mist extractor flooded, or outlet backpressure.
2. Vessel level control
   • Oil and water interface levels (sight glass + LT/LG).
   • Dump valves: stroke them (if safe/procedure allows); check instrument air and solenoid status.
   • Liquid-locked separator → gas carry-under or gas flow collapse through meter.
3. Pressure control valve (PCV) / backpressure
   • Set point vs. process variable.
   • Controller in MAN vs. AUTO? Output frozen?
   • Nuance: After power blip, controllers can sit in fail position.
4. Dump destination
   • Tanks: high level → shutdowns on LSH.
   • Lease automatic custody transfer (LACT): BS&W trip, charge pump off, recycle.
   • Water to SWD: injection pump down or permit pressure limit.
5. Carry-over / foam / emulsion
   • Sudden foam (surfactant, condensate banks) blinds level controls.
   • Check defoamer/demulsifier injection pumps primed and rate correct.
6. Heat (if heater-treater)
   • Firetube on, bath temp, fuel gas scrubber not dumped dry/liquid-full.
   • Cold night Ohio ambient: treaters and fuel gas regulators ice up.
7. Filters / strainers / sand
   • ΔP across inlet strainer; dump sand from traps.
   • ESP wells can trash separators overnight after a pump degradation event.
8. VRU / vapor recovery / flare
   • VRU down can force tank pressure trips and cascading well SDVs on some designs.

Phase 3: Line Pressure, Header, Metering & Takeaway

This is the highest-frequency real cause of pad-wide % drops.

1. Sales / custody line pressure
   • Pad outlet pressure vs. midstream contractual suction.
   • Overnight compressor station recycle, unit trip, or capacity constraint → pad backpressure up → wells unload less liquids/gas.
2. Pad header balance
   • Individual well contribution valves; equalizing valves left wrong after maintenance.
   • Check for one well cross-flowing into another at night (check valves failed).
3. Metering integrity (false decline)
   • Orifice: DP cell equalization valve status, manifold leaks, freeze on sensing lines (classic winter Ohio).
   • Ultrasonic/Coriolis: alarm logs, speed of sound, drive gain, density out of range.
   • Pulse totalizers / RTU scaling factors after firmware blip.
   • Compare allocated volume vs. raw pulse counts vs. tank straps.
4. Chromatograph / heating value
   • If revenue gas “dropped” but volume didn’t, confirm not a composition/BTU reporting artifact. Still investigate volume first.
5. Flowline network
   • Buried line freeze/hydrate at low spots; methanol pump status; drip pots full.
   • Right-of-way disturbance, third-party hit, or valve box vandalism (document).
6. Call midstream (after you have numbers)
   • Ask: station suction trend 1800 to 0600 local, any recycle, pig, ESD, or capacity allocation cut.

Nuance: If all wells show higher WHP and lower rate in the same hour, prioritize takeaway/separator backpressure over reservoir or single-well lift.

Phase 4: Artificial Lift Diagnostics

Match to installed lift on Pad 7 wells.

A. ESP

1. VSD: running Hz, output amps, voltage, insulation alarms, underload/overload trips.
2. Intake pressure (if downhole gauge), motor winding temp, vibration.
3. Underload + low amps → pump-off, low inflow, or gas lock; overload → worn pump, solids, emulsion viscosity.
4. Check wellhead amp clamp vs. SCADA (CT error).
5. Recent power quality: utility flicker overnight?
6. Do not repeatedly hard-start a hot-tripped ESP: insulation damage risk; capture fault log first.

B. Gas Lift

1. Injection rate and casing pressure vs. design.
2. Compressor discharge, dryer, and manifold chokes.
3. Valve status: unloading vs. orifice; possible tubing hole (CHP ≈ THP).
4. Hydrate in injection line (cold night).
5. Allocation: injection stolen by another well on common manifold.

C. Rod Pump / Pumpjack

1. Unit on, prime mover faults, belt, gear box noise.
2. POC / pump-off controller cards: fillage %, cards shape (fluid pound, gas interference).
3. Tubing pressure build when shut briefly: standing/traveling valve check only if competent and procedure-approved.
4. Stuffing box leaks → false tank loss (not formation).

D. Plunger Lift

1. Arrival count overnight vs. baseline.
2. Fossils: long after-flow, no arrival → load or line pressure too high.
3. Lubricator, motor valve, and arrival sensor icing.

E. Intermittent / Hybrid

1. Cycle timers drifted after RTU reboot.
2. Confirm schedule vs. actual solenoid actuation.

Nuance: Lift failure on the #1 well can equal ~18% pad drop by itself. Always rank wells by prior 7-day rate before assuming pad-wide cause.

Phase 5: Wellbore / Reservoir Quick Hits (Still Ops-Level)

1. Compare each well’s flowing bottom-hole pressure proxy (WHP + lift design) to normal.
2. Water cut jump → possible breakthrough, lift not handling denser fluid, or separator mis-metering water as oil.
3. Sand/solids production after ESP wear or choke open too far.
4. Offset ops: nearby frac (if any): Ohio multi-pad densification; look for pressure communication.
5. Do not call “formation damage” until surface, lift, and takeaway are clean.

Phase 6: Data Package to Pull Before Calling Engineering

Engineering should receive a single, clean package, not a phone call with “rates are down.”

1. Production & Allocation

• Hourly (or 15-min) gas, oil, water by well and pad total: last 14 days, highlight last 48 hours
• Last official well tests (rate, WHP, choke, duration, GOR, WC)
• Tank straps / LACT tickets / SWD volumes overnight (reconcile sales vs. theoretical)

2. Pressure & Temperature Trends

• WHP, CHP, flowline, separator P/T, sales line P: 72 h at high frequency
• Any downhole gauge PIBHP/PDHP if installed
• Ambient temp overnight (hydrate correlation)

3. Artificial Lift Exports

• ESP: VSD fault history, amps, Hz, PI, motor temp: 72 h + event log
• Gas lift: injection MCFD, CHP, compressor status
• Rod: POC cards last 20 cycles; runtime %
• Plunger: arrival log

4. Facility & Alarm Logs

• SCADA alarm printer / historian: ESD, LSH/LSL, PSH/PSL, SDV close, meter faults
• Valve position feedback (if digital)
• Power outage / RTU reboot timestamps
• Chemical pump runtime (scale, paraffin, methanol, defoamer)

5. Metering & Midstream

• Raw DP/static/temp for orifice runs; Coriolis density/drive gain
• Any midstream nomination cut, station suction chart, or imbalance notice
• Chromatograph snapshots if used for allocation

6. Operations Narrative (one page)

• Who discovered, time stamp, weather
• What was touched overnight (chokes, dumps, samples, filter changes)
• Visual findings (ice, leaks, valve positions found wrong)
• Actions already taken and result (e.g., “opened wing ½ turn, rate +X”)
• Safety readings (H₂S/LEL max)

7. Photos / Short Video

• Choke position indicators, sight glasses, iced sensing lines, VSD fault screen, valve handle positions

8. Well schematic & set points (attach existing)

• Lift design, normal WHP band, normal separator set points, MAOP of flowlines

9. Permit / Compliance flags

• Any flare volumes overnight, truck water hauls off-schedule, SPCC-relevant releases

Nuance: Send CSV/historian export + one PDF summary. Engineers lose hours when Ops only sends a screenshot of yesterday’s allocation email.

Tiered Escalation (Ops → Engineering → TOC)

De-escalation: Rates within 5% of baseline stable 6 to 12 h, alarms clear, no integrity flags, documentation filed.

Hazards

• Well control / unexpected pressure on tree or annulus
• H₂S / hydrocarbon release while breaking meter lines or thief hatches
• Hydrate ice plug dislodging as projectile / sudden flow
• ESP stored energy / unexpected start
• NORM on filters; benzene in condensate samples
• Vehicle/line-of-fire at pumpjacks
• Night/winter slips on Ohio locations
• Incorrect valve lineup causing overpressure of low-MAOP equipment

Controls

• Engineering: PSHL/PSLL, SDV, ESD, flame arrestors, relief valves per API 521 design basis; meter dual-path where installed
• Administrative: This protocol; MOC for set-point changes; LOTO on meters/VSD; two-person for breaking containment; Ohio EPA / ODNR reporting thresholds awareness
• PPE: As listed
• Mitigations: Live gas monitoring; stop-work authority; do not bypass safety PLCs without written authorization

ROI Nuance: A disciplined 90-minute Ops diagnostic typically costs a few labor hours. Unnecessary ESP pull or engineering fire drill on a frozen DP cell can run $50k to $250k+ and days of deferred production. At pad rates common in Ohio liquids-rich gas, 18% down on a 50 to 100 MMscfd-equivalent pad is material overnight revenue: speed with data quality matters.

Field-Ready Quick Checklist (Print / Tablet)

First 30 minutes

• Safety gas check / visual leak
• Confirm 18% real: by well, by phase
• SCADA freeze + 72 h export started
• Sales line pressure vs. normal
• Separator levels, dumps, PCV mode
• Top 3 wells: choke, SDV, WHP/CHP

First 60 to 90 minutes

• Meter DP lines / Coriolis health
• Lift: ESP faults / GL injection / rod cards / plunger arrivals
• Tanks / LACT / SWD constraints
• Midstream suction status
• Methanol / heat / chemical pumps
• Narrative + photos

Before engineering call

• Data package complete (Section Phase 6)
• What you already tried and result
• Clear ask: “Need review of X well ESP curve” vs. “Pad down, unknown”

Worked Example Logic (How to Think on Location)

Assume Pad 7 yesterday: 12.0 MMscfd + 1,200 bbl condensate. Overnight: 9.8 MMscfd + 990 bbl (~18% BOE).

• If sales pressure +80 psi and all WHP ↑ → midstream/takeaway or pad PCV first.
• If sales pressure flat, Well 3 ESP undervoltage at 02:14 and Well 3 was 20% of pad → lift on Well 3 first.
• If volumes down but tank straps match yesterday → meter/allocation fault.
• If gas down, oil flat, separator oil level high → gas meter or foam/level control.
• If only water rate “down” and oil up slightly → interface/brine dump stuck (allocation optics).

Always reconcile energy balance: reservoir + lift + surface + takeaway + measurement. The broken link is almost never “all five at once.”

References

• OSHA 29 CFR 1910.119 (PSM where applicable), 1910.146, 1910.147 (LOTO), 1910.1000 (air contaminants)
• API RP 54 (fire protection / operations safety), API RP 500/505 (classified areas), API RP 11S series (ESP), API RP 11V (gas lift), API 521 (pressure-relieving)
• API MPMS (metering / proving practices)
• Ohio Department of Natural Resources (ODNR) Division of Oil & Gas resources management rules; Ohio EPA air/SPCC as applicable
• Company SEMS / operating procedures; manufacturer VSD/ESP fault guides
• PHMSA / midstream interconnect operating agreements (takeaway pressure)

Mission locked in. Run the ladder in order:

That sequence finds the majority of “mystery” 15 to 20% overnight drops without waking the wrong people or pulling the wrong pump.

Pigging Pre-Run Verification Checklist & Coordination Plan
48-Hour Confirmation Window: 8-Inch Gathering Segment (Pennsylvania)

Segment: 8-inch gathering line (PA), next-week pig run

Purpose

Establish a complete, auditable 48-hour pre-pig confirmation package so the pig run executes with zero unplanned isolation errors, no downstream process upsets, full PHMSA/PADEP notification compliance, and controlled pressure/flow conditions. This checklist locks valve lineups, isolation integrity, pig trap readiness, product/liquid handling, communications, and emergency readiness before the pig is loaded.

Scope

Applies to the designated 8-inch gathering segment in Pennsylvania, launcher/receiver facilities, associated block valves, bypasses, drain/vent systems, SCADA/telemetry points, and all downstream receipt points (compressor station, processing plant, interconnect, or tank battery). Covers cleaning, batching, or inline-inspection (ILI) pigs as scheduled. Excludes live hot-tap or non-standard specialty tools unless separately engineered. Personnel: Pipeline Operations, Integrity, Control Room, Field Techs, HSE, and notified downstream operators.

Responsibilities

• Pipeline Operations Supervisor / Pigging Lead: Owns checklist completion, final go/no-go, valve lineup sign-off, and 48-hour confirmation log.
• Control Room / Gas Control: Confirms SCADA setpoints, pressure/flow windows, alarm inhibits/restores, and real-time monitoring plan.
• Field Technician / Valve Crew: Physically verifies valve positions, lock/tag status, trap doors, seals, and drains; executes lineup under LOTO where required.
• Integrity / ILI Coordinator (if ILI pig): Confirms tool specs, speed window, tracking plan, and data quality requirements.
• HSE / Spill Response: Verifies spill kits, containment, PADEP notification readiness, and SDS/product data.
• Downstream Receiver (plant, compressor, interconnect operator): Acknowledges receipt of formal notification, confirms capacity/handling readiness, and provides 24/7 contact.
• Nuance (PA gathering): Many PA gathering systems feed midstream compressors or processing; confirm whether the segment is under PHMSA gas gathering (49 CFR 192) or hazardous liquid (195) applicability and whether it is Type A/B/C gathering: documentation must match the actual regulatory tier.

PPE

• Hard hat (ANSI Z89.1)
• Safety glasses with side shields (ANSI Z87.1)
• Flame-resistant clothing (NFPA 2112): gathering/compression corridors
• Steel-toe boots (ASTM F2413)
• Cut-resistant / chemical-resistant gloves for trap and drain work
• Hearing protection where >85 dB (compressor/trap areas)
• H₂S / multi-gas monitor if sour or liquid hydrocarbon vapors possible (action levels per site H₂S plan; typically ≥10 ppm H₂S evacuate/upwind)
• Face shield + splash protection when breaking trap flanges or draining
• Fall protection if trap platforms require (OSHA 1926.501 / 1910.28)
• Nuance: PA winter/shoulder-season runs: add ice cleats, cold-weather FR layers, and verify trap heating/heat trace is functional before seal checks.

Procedure: 48-Hour Confirmation (T-48 Hours Through T-24 Hours)

Phase 1: Documentation & Regulatory Lock (T-48)

1. Pull and verify current alignment sheets, P&IDs, valve book, and last pig run report for the 8-inch segment. Confirm MAOP, normal operating pressure, and any temporary pressure reductions.
2. Confirm pig type, diameter/cup OD, weight, bypass ports, transmitter (if tracked), and max allowable differential. Match launcher/receiver barrel length and kicker/bypass sizing to pig length.
   • Nuance: 8-inch gathering often has tight bends, unbarred tees, or reduced-port valves: verify pig can negotiate every fitting; if ILI, confirm gauge plate / deformation history.
3. Verify PHMSA / operator notification and PADEP expectations: internal Management of Change (MOC) closed; if the run could affect jurisdictional reporting or abnormal operations, document per 49 CFR 192/195 and company SEMS/OPS procedures.
4. Confirm product in line (gas, wet gas, condensate, produced water slug risk). Update SDS packet at launcher and receiver.
5. Print and stage this checklist + valve lineup sheet + notification log in the job package.

Phase 2: Downstream & Stakeholder Notifications (T-48: Mandatory Written + Verbal)

1. Issue formal written notification (email + phone) to all downstream operators no later than 48 hours before launcher pressurization / pig launch. Include:
   • Segment ID, pig type, estimated launch time window, estimated receive time, expected speed (e.g., 3 to 10 ft/s gas; follow company ILI spec if smart pig)
   • Expected liquids / debris volume and handling requirements
   • Pressure/flow changes or brief interruptions
   • Primary/backup contacts and emergency stop authority
   • Request for written acknowledgment of readiness (capacity, tankage, slug catcher, filter-sep, flare/vent if needed)
2. Notify Control Room / Gas Control and any upstream producers feeding the segment (shut-in or rate curtailment may be required).
3. Notify land/ROW and local emergency management if company policy or PA local ordinance requires (rural PA townships sometimes want heads-up on heavy trap traffic).
4. Confirm one-call / excavation status only if temporary tracking antennas or excavation for markers is planned (otherwise N/A).
5. Log acknowledgments: name, time, call sign, readiness yes/no, restrictions.
   • Nuance (PA): Downstream compressor stations on Marcellus/Utica gathering frequently have strict liquid limits: if the pig will push a liquid slug, confirm slug catcher level, dump valve function, and high-level ESD setpoints before you launch. Failure here is the #1 cause of downstream trips.
6. Escalation: If any downstream party cannot accept the pig or liquids in the planned window, stop and reschedule: do not “hope the slug is small.”

Phase 3: Valve Lineup Confirmation (Field Walk-Down + SCADA Cross-Check)

Complete a physical walk-down; do not rely on last month’s lineup.

1. Main line block valves (upstream of launcher, downstream of receiver, intermediate MLVs)
   • Confirm open for pig passage (full-port). Document position indicators and SCADA status.
   • Nuance: Reduced-port or partially closed valves will stop or destroy an 8-inch pig: verify full open travel and stem position.
2. Launcher isolation valves
   • Barrel isolation (mainline side): confirmed closed and depressured for loading window per procedure, then lined up for launch sequence as timed in the run plan.
   • Kicker valve: closed until launch; verified operable.
   • Bypass / mainline equalizing valves: positioned per company pigging SOP (typically bypass open to keep flow on mainline until launch).
   • Trap vent and drain: operable, directed to containment/tank; no unknown outlets to ground.
3. Receiver isolation valves
   • Barrel isolation ready for receive sequence.
   • Bypass configured so pig can enter barrel without dead-heading the gathering system.
   • Motor-operated or actuated valves: local/remote mode confirmed; torque switches and limits tested recently.
4. Excluded / protected laterals and dead legs
   • All laterals that must not receive the pig: closed and locked/tagged or confirmed closed with positive isolation.
   • Instrument taps, sample points, and relief paths: verified pig cannot enter or leave unprotected.
5. Relief, ESD, and blowdown valves
   • Confirm PSV setpoints appropriate for planned launch/receive differentials; no gagged reliefs.
   • ESD valves that would strand the pig: place in “pigging mode” or temporary bypass per MOC with compensatory monitoring.
6. Lockout/Tagout
   • Apply LOTO on energy sources only as required for trap door entry; maintain a live lineup sheet that shows which valves are under LOTO vs. operational for the run.
   • OSHA 1910.147 compliance; group lockbox if multiple crafts.
7. Sign-off: Two-person verification (operator + supervisor) on critical path valves. Photograph position indicators where practical.
   • Nuance: PA gathering laterals often have farm taps or small producer ties, a single missed open lateral can lose the pig or create a high-pressure backflow into low-pressure piping. Walk every tie-in on the alignment sheet.

Phase 4: Launcher / Receiver Mechanical & Integrity Readiness

1. Trap doors: seal surfaces clean, O-rings/gaskets correct durometer and size, door interlocks and pressure-warning devices functional (API RP 1110 / company trap standard).
2. Closure devices: swing-bolt or clamp hardware torqued per spec; no cracked ears.
3. Bars / trays / carts: rated for pig weight; 8-inch cleaning pigs and ILI tools can be heavy: confirm lifting plan (OSHA crane/hoist if used).
4. Kicker and bypass strainers/screens: clear.
5. Drains: winterized; heat trace on and proven; drain to 110% containment or vacuum truck hookup.
6. Signage and exclusion zone: barricades, “pigging in progress” tags, ignition control if hydrocarbon liquids.
7. Tracking: AGMs / geophones / GPS points loaded; landowner access confirmed if needed.
8. Communications test: radio/cell/satellite between launcher, receiver, control room, and tracking crew: dead spots common in PA hollows; stage repeaters or runners.

Phase 5: Process & Hydraulic Window

1. Confirm flow rate and pressure band that keeps pig velocity in target range (too slow = stuck risk; too fast = tool damage / cup wear).
2. Liquid management: estimate pushed liquids; stage vacuum trucks or confirm tank capacity at receiver.
3. Gas quality / H₂S / NORM: if historically present in PA gathering liquids, stage monitors and NORM survey plan for debris.
4. Weather hold criteria: high winds (trap door), lightning, flood risk at low receiver sites, icing on valves.
5. SCADA: trends clean; alarms configured; temporary inhibit list documented with restore time.

Phase 6: Emergency & Contingency (Confirm 48 Hours Out)

1. Stuck-pig procedure staged (differential limits, reverse flow authorization, cut-out plan owner).
2. Spill kit and boom at launcher and receiver; PADEP spill hotline numbers in the package (company internal first, then state as required).
3. Medical / medevac and nearest facility; driving directions from both traps.
4. Stop-work authority briefed to every person on the job.
5. Night-run lighting and fatigue plan if the window extends after dark.

Phase 7: Final 48-Hour Go / No-Go Gate

Hazards

• Pressure release / door blow open
• Fired or unfired hydrocarbon release; LEL
• Pig launch under incomplete isolation (downstream dead-head or open lateral)
• Liquid slug overwhelming compressor suction or plant inlet
• H₂S / benzene / NORM in trap debris
• Stored energy in actuators; incorrect MOV position
• Vehicle/traffic on shared PA lease roads
• Struck-by during pig handling
• Environmental release to soil/water (PA Chapter 78/78a and SPCC exposure)

Controls

• Engineering: full-port valves, door interlocks, pressure gauges on barrel, relief protection, containment berms (110% where required), SCADA differential alarms
• Administrative: this 48-hour checklist, dual verification, written downstream acknowledgment, MOC, JSA day-of, toolbox talk, stuck-pig playbook
• PPE: as listed
• Mitigations: velocity control, staged liquids handling, weather hold, stop-work authority
• Nuance: Treat “short” gathering segments with the same discipline as long transmission runs, most PA gathering pig incidents are lineup and liquids handling, not exotic metallurgy.

Day-Of Bridge (Not a substitute for 48-hour work)

Re-verify critical valves, atmospheric tests before door opening, final downstream “still clear” call 1 hour prior, launch per SOP, continuous tracking, receive, drain, debris characterization, restore lineup, remove temporary inhibits, and close the report.

References

• 49 CFR Part 192 (gas) / Part 195 (hazardous liquids) as applicable to the segment
• PHMSA pigging and integrity guidance; operator O&M manual
• API RP 1110 (pipeline in-line inspection / associated practices as applicable)
• API RP 1160 / RP 1175 elements for integrity and control room coordination where adopted
• OSHA 29 CFR 1910.147 (LOTO), 1910.119 (if PSM-covered), 1910.1200 (HazCom), 1910.132 to 138 (PPE)
• PADEP requirements for releases and Chapter 78/78a (oil & gas) / applicable stream protection
• Company pigging SOP, trap manual, MOC procedure, and emergency response plan
• NFPA 2112 / site hot-work and ignition control standards

Mission locked in. Execute the 48-hour gate with dual-verified lineups and written downstream acknowledgments and that 8-inch pig run stays controlled, compliant, and uneventful. If liquids or a compressor trip risk shows up in the notification roundback, slip the window; do not force it.