A Case Study in Evaluating Technical Options for Well Abandonment in an Aging Offshore Field

Transcription

1 A Case Study in Evaluating Technical Options for Well Abandonment in an Aging Offshore Field Tom Leeson: Reverse Engineering Stewart Buchan: Quadrant Energy Aberdeen: June

2 HARRIET JOINT VENTURE (HJV) 45 Wells across 9 Unmanned Structures 4 Suspended Subsea Wells 4 Land Wells 2 -

3 SCOPE OF WORK Develop AACE Class IV Time and Cost Estimates for Abandonment Review offset well abandonment results Evaluate local regulatory constraints on abandonment design Develop individual well methodologies for a Conservative case & an Opportunity case Develop Technical Risk Register Develop individual well durations Develop cost database Undertake Monte Carlo probability analysis of overall Project Cost for both Cases Evaluate Opportunities for Cost Minimisation especially the potential for using Rigless Techniques 3 -

4 CHALLENGES & OPPORTUNITIES Well Characteristics Mudline Hangers and Annuli Cemented at surface/mudline Sustained B and C Annulus Pressures: Sources Uncertain Total Losses to ~ 650m and unknown cement top in B Annulus Shallow Gas Bearing Zone(s) with limited flow potential: ~1,000m-800m (Windalia/Gearle) Tubing & Wellhead Integrity Limited High s.g. Tail Cement Volumes Effectiveness of existing Suspension Plugs Multiple Production Reservoirs (5 Wells) Goal-Oriented Regulation Limited Platform Load Capacity & Water Depth (30m-6.5m) 4 -

5 ABANDONMENT PHILOSOPHY CONSERVATIVE CASE Isolation Barrier required across the wellbore Single Combination barrier permitted Hydrocarbon Cross-flow not permitted (deeper formation in 5 wells) Tubing and GLM leaks assumed to prevent thru tubing operations Sustained B and C annulus pressures assumed to originate from reservoir formation Remedial cementation of cemented annuli via section milling Remedial cementation of casing with uncertain cement and liners, by perf and wash technology Plugs below tailpipe only when hole angle <75deg Cementing of 7 liner in 12 ¼ hole: unreliable at high hole angle Windalia and Gearle require isolation from surface at 13 3/8 shoe due to loss formations above this point 5 -

6 ABANDONMENT METHODS EXAMPLE 1 Conservative Case Kill Well and Plug Tailpipe N/D XT & N/U BOP Pull Tubing & Set BP in Liner Hanger Section Mill Casing & Set Cement Plug #1 Set Squeeze Packer at 13 3/8 Shoe Circulate or Squeeze Annulus Sting Out and Set Cement Plug #2 on Top Cut & Pull Inner Casings Set Bridge Plug Set Plug #3 6 - Well Status: Inactive Wellhead Test Failures No recorded issues. Annulus Pressure Sustained B Annulus Pressure Cut and Pull Casings below Bridge Plug Lead 250 m Lead 650 m Tail 705m Squeeze Packer Section Mill Casing Bridge Plug Cut and Pull Tubing below Bridge Plug Abandoned Agincourt-6H EOT 1,574 m Lead 3,585 m Primary Data Source for this work: Well Summary and Integrity Review Well Name: Artreus-1 Conservative Case P&A Schematic Perfs: 3,680 3,868 m 8 ½ 4,046 m ML to KB: 49.8 m Water Depth: 8.1 m 20" 49.5 m No Cement Details. Drilling Rig: Ensco 56 Spud Date: September, 2005 Rig Release: September, 2005 Cement Note No cement details in report. TTOC from Completion Schematic. Cement Plug #3 Bridge Plug Cement Plug #2: Perf and squeeze cement at 13 3/8" Shoe. 13 3/8" Casing m No Cement Details. Cement Plug #1 9 5/8" x 7" Liner Hanger/Packer 1,365 m 9 5/8" Casing Window 1,400m 9 5/8" Casing Window 1,404 m No Cement Details. 7" x 4 ½ AHC 1,554 m Set Plug in Nipple 7" Liner 4,043 m No Cement Details. RAW 28 th December, 2016

7 ABANDONMENT PHILOSOPHY OPPORTUNITY CASE Changes from Conservative Case Sustained annular pressures assumed to be from Windalia/Gearle Still need Annular Reservoir Barrier in 7 wells Quality of unknown casing cementation can be verified successfully by logging Small tubing leaks do not prevent through tubing cementation operations Cross flow between hydrocarbon reservoirs permitted No surface plug required 7 -

8 ABANDONMENT METHODS EXAMPLE 2 Opportunity Case Kill Well and Plug Tailpipe N/D XT & N/U BOP Pull Tubing Verify Casing Cement Set Plug#1 on Bridge Plug & Verify Set Squeeze Packer at 13 3/8 Shoe Circulate or Squeeze Annulus Sting Out and Set Cement Plug #2 on Top Well Status: Inactive Wellhead Test Failures No recorded issues. Annulus Pressure Sustained B Annulus Pressure Cut and Casings and Conductor at ML Lead 250 m Lead 650 m Tail 705m Squeeze Packer Bridge Plug above hanger Cut and Pull Tubing below Bridge Plug Lead 3,585 m Well Name: Artreus-1 Opportunity Case P&A Schematic Abandoned Agincourt-6H EOT 1,574 m Perfs: 3,680 3,868 m 8 ½ 4,046 m ML to KB: 49.8 m Water Depth: 8.1 m 20" 49.5 m No Cement Details. Drilling Rig: Ensco 56 Spud Date: September, 2005 Rig Release: September, 2005 Cement Note No cement details in report. TTOC from Completion Schematic. Cement Plug #2: Perf and squeeze cement at 13 3/8" Shoe. 13 3/8" Casing m No Cement Details. Cement Plug #1 9 5/8" x 7" Liner Hanger/Packer 1,365 m 9 5/8" Casing Window 1,400m 9 5/8" Casing Window 1,404 m No Cement Details. 7" x 4 ½ AHC 1,554 m Set Plug in Nipple 7" Liner 4,043 m No Cement Details. Primary Data Source for this work: Well Summary and Integrity Review RAW 28 th December,

9 DURATION ESTIMATES Duration (Days) Liftboat based Durations Low Most Likely High Position Rig LB Move in on DP and Jack Up LB Skid Cantilever and prepare for operations LB Install walkway P&A Preparations LB Tubing and Annulus Riser and PCE preparations Prepare Well LB Rig up W/S PCE & riser lines to tree & annulus LB Bullhead kill fluid to formation LB R/U wireline drift well and lock open SSSV Through Tubing Reservoir Plug LB Drift to Packer & set plug in tailpipe LB Punch/sever tubing and circulate annulus clean LB circulate 800' balanced cement plug via tubing and verify LB RIH CBL and Log Annular cement LB RIH and set squeeze packer above perforations LB Mix and squeeze cement into perfs LB sting out of packer and spot cement plug on packer and verify Pull Completion LB sever/punch tubing at shallow depth 13 3/8" shoe) LB set temporary plug in Tubing hanger LB Remove Tree LB Nipple up BOP's LB RIH and latch tubing hanger and recover upper tubing section LB RIH and latch tubing hanger and lift tubing string LB mix and spot 800' cement plug thru tubing and verify LB Pull Completion - Normalised to 2000m length LB RIH, latch and retrieve packer Prepare Cased Hole LB cut and pull 9 5/8" casing LB Cut & Pull 13 3/8" casing LB RIH CBL and Log Annular cement Isolate Cased Hole LB RIH Bridge Plug, set, sting out, spot cement on top and verify LB RIH and set Bridge Plug/Squeeze Packer LB Perforate Casing and Circulate annulus clean LB Mix and squeeze/circulate annulus cement plug LB WOC and verify LB RIH, spot cement plug and verify Intermediate Isolation LB cut and pull 9 5/8" casing LB RIH Squeeze packer and set LB Perforate Casing and Circulate annulus clean LB Mix and squeeze/circulate annulus cement plug LB Sting out, spot cement and verify LB circulate balanced cement plug via tubing and verify LB Cut & Pull 9 5/8" casing LB Cut & Pull 13 3/8" casing LB RIH Bridge Plug, set, sting out, spot cement on top and verify Surface Isolation and Conductor LB Cut 9 5/8" casing and N/D BOP LB Skid back Cantilever LB Cut Casing & Conductor LB Recover conductor (HA/Linda & Wonnich only) LB Confirm Conductor Severance with Vessel Crane MOB-DEMOB LB Jack Down and move off location LB Pull Completion - Normalised to 2000m length Triang(17.875,39,72) % 80.0% 10.0% 9 -

10 SCHEDULE OPTIONS - EXAMPLE Option 1: Mob Liftboat first, finish wells with the Rig Option 2: Mob Rig first, finish remaining wells (and remove facilities?) with the Liftboat 10 -

11 PRINCIPAL RESIDUAL TECHNICAL RISKS Source of Sustained Annulus Pressures Potential impact: Reservoir isolation via section milling Unknown Quality and Extent of Annular Cement Failed Cement Barriers, delays Pulling Casing Section Milling in High Angle Hole Delays Surface Isolation Valve Functionality Circulation Failures Casing Leaks Failed Barriers, Compromised Circulation Paths Pressure and/or Undetonated Guns below Shallow Cement Plugs Alternative Intermediate Abandonment Threat Event Preventative Barriers Mitigating Controls Likelihood Safety Environment Asset Reputation Further Actions Rig up on well 2 Annulus valves seized inability to access Wellhead maintenance 6. PROBABLE: 1. NEGLIGIBLE: First Aid 1. NEGLIGIBLE: 3. MODERATE: Material 1. NEGLIGIBLE: Short or not in place analulus and/or programme prior to rig Consequence or event injury Environmental damage or production term local impact has occurred within the lasting less than 1 week loss/deferment between (community) circulate arrival Company (Between 1 $10M-$50M and 10 incidents every 10 years) 3 Pressure on A annulus leak from Bleed down pressure prior 7. EXPECTED: With the 1. NEGLIGIBLE: First Aid 1. NEGLIGIBLE: 3. MODERATE: Material 1. NEGLIGIBLE: Short If required, design more existing controls in place, injury Environmental damage or production term local impact hydrocarbon to arrival and establish if complex well kill is expected to occur in lasting less than 1 week loss/deferment between (community) formation via failed related to tubing/packer most circumstances at $10M-$50M packer, tubing and/or leak or B Annulus the location during the casing lifecycle phases or phases being assessed. 4 Pressure on B and/or C Annuli leak from hydrocarbon formation via failed cement and/or casing Mill shallow cement plug 6 Pressure below Loss of Containment cement plug 7 undetonated guns below squeeze packer to be milled Section Milling 25 Milling in high angle hole (~>45deg) Hazard Identification fishing of guns Snapped knives, Loss of BHA Setting Cement plug in casing/annulus 29 Anulus cement lower change to than anticipated abandonment method 30 Annulus cement higher than expected change to abandonment method 31 Casing leak(s) effective circulation prevented Engineer to Populate Bleed down pressure prior to arrival and establish if source is from reservoir or shallow formations Careful control of milling parameters, establish cement behind casing with log prior to milling window well control and kill weight brine in place contingency plans and tooling programme contingency required including alternative tooling programme contingency required including alternative tooling programme contingency required including alternative tooling 7. EXPECTED: With the existing controls in place, is expected to occur in most circumstances at the location during the lifecycle phases or phases being assessed. 5. LIKELY: Has occasionally occurredwithin the industry & the team has had first hand experience (Between 1 and 10 incidents every 100 years) 5. LIKELY: Has occasionally occurredwithin the industry & the team has had first hand experience (Between 1 and 10 incidents every 100 years) 7. EXPECTED: With the existing controls in place, is expected to occur in most circumstances at the location during the lifecycle phases or phases being assessed. 6. PROBABLE: Consequence or event has occurred within the Company (Between 1 and 10 incidents every 10 years) 7. EXPECTED: With the existing controls in place, is expected to occur in most circumstances at the location during the lifecycle phases or phases being assessed. 7. EXPECTED: With the existing controls in place, is expected to occur in most circumstances at the location during the lifecycle phases or phases being assessed. 1. NEGLIGIBLE: First Aid injury 3. MODERATE: Lost Time Injury (LTI) 1. NEGLIGIBLE: First Aid injury 1. NEGLIGIBLE: First Aid injury 1. NEGLIGIBLE: First Aid injury 1. NEGLIGIBLE: First Aid injury 1. NEGLIGIBLE: First Aid injury Severity 1. NEGLIGIBLE: Environmental damage lasting less than 1 week 2. MINOR: Environmental damage lasting from 1 week to 1 month 1. NEGLIGIBLE: Environmental damage lasting less than 1 week 1. NEGLIGIBLE: Environmental damage lasting less than 1 week 1. NEGLIGIBLE: Environmental damage lasting less than 1 week 1. NEGLIGIBLE: Environmental damage lasting less than 1 week 1. NEGLIGIBLE: Environmental damage lasting less than 1 week 3. MODERATE: Material or production loss/deferment between $10M-$50M 3. MODERATE: Material or production loss/deferment between $10M-$50M 3. MODERATE: Material or production loss/deferment between $10M-$50M 3. MODERATE: Material or production loss/deferment between $10M-$50M 3. MODERATE: Material or production loss/deferment between $10M-$50M 3. MODERATE: Material or production loss/deferment between $10M-$50M 3. MODERATE: Material or production loss/deferment between $10M-$50M 3. MODERATE: Short term national coverage, JV oversight impact 3. MODERATE: Short term national coverage, JV oversight impact 1. NEGLIGIBLE: Short term local impact (community) 1. NEGLIGIBLE: Short term local impact (community) 1. NEGLIGIBLE: Short term local impact (community) 1. NEGLIGIBLE: Short term local impact (community) 1. NEGLIGIBLE: Short term local impact (community) If required, remove well from rigless programme and require remedial cementation of production casing with rig. Brief crews and develop contingency plans investigate alternate of cementing in guns at lower depth downhole Lost tubular will need to be fished causing additional duration - factor into cost estimate as a risk develop programme contingency for additional annulus cementation by perf and wash or annulus circulation develop programme contingencies for cementation higher in wellbore, perf and squeeze/wash, and/or section milling develop programme contingencies for loss control, cement squeeze and/or alternative abandonment 11 -

12 ADDITIONAL STRATEGIC RISKS & OPPORTUNITIES Regulator Agreement Unit Cost Inflation (Rates are Low, but for how long?) Alternative (Local) Liftboat New & Emerging Technologies/Methods Logging thru tubing Reduced cement plug length Alternatives to conventional section milling Alternative barrier materials Removing the need to pull tubing Synergies with Facilities Decommissioning Suspended Well Risk Assessment 12 -

13 COST ANALYSIS Single Mobilisation of Each Asset * Liftboat and Rig mobilised to/from Singapore* * Exception: US$ 25k/day amortization for rig opportunity case (based on previous QE experience) Significant Inclusions Safety Case Liftboat Cantilever Mods Supply Base and Dedicated Supply Boats & Helicopters WOW and Cyclone Provision Offset Operations Durations & Recent Unit Costs used where Possible 13 -

14 Values x 10^-8 RESULTS Opportunity Case Total % 80.0% 10.0% Values in Millions ($) Conservative Case P50: 389 rig days plus 184 liftboat days Opportunity Case P50: 137 rig days plus 284 liftboat days 27% cost reduction 14 -

15 MOST LIKELY CASE $$ Opportunity Case Likely Cost $$$$$ Conservative Case Most Likely Case Quantification of Risk Impact Required Example: Additional Surface Plug (~USD17.4M Impact) 15 -

16 RECOMMENDED ACTIONS & CONCLUSIONS Early & Sustained Dialogue with Regulator Follow up Risk Register Actions to Reduce Unknowns Finalise Most Likely Case Liftboat cost savings are limited until rig rate escalates or local liftboat option is feasible Investigate Local Liftboat Options & Contractor Model Confirm Facilities Strategy before Committing to P&A Strategy Significant further cost reduction opportunities through Understanding source of annular pressures Understanding condition of tubulars Alternatives to section milling Challenging multizone isolation, surface plugs etc. Declaring suspended wells as abandoned requires further study 16 -