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Tui Oil Field Decommissioning Application Review Review of SURF and Wells P&A application
New Zealand Environmental protection Agency
Document date 3rd September 2021 418005-00212-PL-REP-00001
Document Title Review of Marine consent submission Intecsea 2Current Rev No.: Document number
Disclaimer
This report has been prepared on behalf of and for the exclusive use of The New Zealand Environmental protection Agency and is subject to and issued in accordance with the agreement between The New Zealand Environmental protection Agency and Intecsea. Intecsea accepts no liability or responsibility whatsoever for it in respect of any use of or reliance upon this report by any third party. Copying this report without the permission of The New Zealand Environmental protection Agency and Intecsea is not permitted.
Company details
Intecsea Tower 2 5995 Rogerdale Rd, , Houston TX 77072
PROJECT 418005-00212-PL-REP-00001: Review of Marine consent submission
Rev Description Author Review Intecsea approval
Revision date
Client approval
Approval date
A Revision description John Cox Alan Stokes
3rd Sept 21 Approval
date JFC AS John cox Initial. Surname
O Issued for use John Cox A Alan Stokes John Cox 9th September
2021
Optional client project number-Optional client document number
John Cox
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Table of contents Executive summary ......................................................................................................................................... 5 Acronyms and abbreviations ......................................................................................................................... 6 1 Phase 2 SSI Decommissioning and Removal .................................................................................. 7
Control Umbilicals: 7 Gas-lift lines 7 Production and gas lift Risers and Riser bases 7 Mid Water Arches (MWA) and Gravity Base Anchors (GBA) 7 Hold-back anchors: 7 Subsea Distribution Unit (SDU) 7 Hydraulic Flying Leads (HFL) and Electrical Flying Leads (EFL) 7
General Review Observations (SSI) 7 Description of the Project Related Vessels and Equipment 8 2.2.1 Construction Support Vessel 8 2.2.5 Remotely Operated Vehicles (ROV) 9 2.3 Field Asset Deconstruction and Recovery Activities 9
1.5.1 Duration of Field Asset Recovery Activities .............................................................................. 9 1.5.2 2.3.2 Production Flowlines / risers ............................................................................................... 9 1.5.3 2.3.3 Umbilicals .................................................................................................................................... 9 1.5.4 2.3.4 Gas lift Coil Tubing and risers ........................................................................................... 10 1.5.5 2.3.5 Gas-Lift Jumpers, Hydraulic Flying Leads and Electrical Flying Leads ............... 10 1.5.6 2.3.6 Gas-Lift Manifold ................................................................................................................... 10 1.5.7 2.3.7 Midwater Arch and Gravity Base ...................................................................................... 11 1.5.8 2.3.8. Production Riser Hold-back Anchors ............................................................................ 11 1.5.9 2.3.9. Miscellaneous Equipment .................................................................................................. 11
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2 Phase 3 Wells Plug & Abandonment ............................................................................................ 13 General Review Observations 13
2.3.1 Section: 2.4.2 Duration of Well Abandonment Activities .................................................. 16 2.3.2 Section: 2.4.4.1 Anchored Semi-submersible MODU ......................................................... 16 2.3.3 Section 2.4.5.1 BOP Tethering System ..................................................................................... 16 2.3.4 Section 2.4.6 Plug and Abandonment ...................................................................................... 16 2.3.5 2.4.6.1 Installation of Abandonment Cement Plugs ........................................................... 17 2.3.6 2.4.6.3 Workover Fluids .................................................................................................................. 18 2.3.7 2.5.3 Discharge of BOP Fluid ........................................................................................................ 18 2.3.8 2.5.4 Discharge of Cement Additives ........................................................................................ 18 2.3.9 7.9.3 Discharge of Hydrocarbons from a Well ...................................................................... 18
4 Discharges Associated with Decommissioning Activities ........................................................... 26 2.5 General 26
4.1.1 2.5.1 Discharge of Biocide Inhibited Seawater ...................................................................... 26 4.1.2 2.5.2 Discharge of Residual Hydrocarbons ............................................................................. 26
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Executive summary The report covered in this summary is for the Phase 2, SSI disconnection and removal and Phase 3, Well Plug and abandonment this summary does not cover the scope of the Phase 1 activities for the disconnection and removal of the FPSO. After a detailed review by Intecsea and our wells partner Vysus Group it is the conclusion that the document as presented meets the international and regional standards and regulations that we, Intecsea and Vysus, have experience for similar scopes of work related to both the SSI removal and the plug and abandonment of the existing well scope. It is noted from the report that Aotearoa Fisheries did not respond to the consultation. Aotearoa Fisheries are managed and overseen by the Maoris fishing commission. They, Aotearoa Fisheries, have an existing interest which could potentially be adversely be affected by this application. Appendix H the Consultation log has no reference to any communications with Aotearoa Fisheries. For the sake of good order and to answer any criticism the communications and their dates should be listed in Appendix H of the document. It is noted in several sections of the review that this document is not a detailed engineering solution and it is understood that the detailed engineering will be carried out by the chosen SSI removal contractor and the well abandonment contractor however notes have been made that certain areas need to be followed up during the detailed engineering phase to ensure that any risks or areas not covered in detailed within this consent application are detailed into both the SSI and the P&A engineering and execution scopes.
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Acronyms and abbreviations Acronym/abbreviation Definition
AHT Anchor Handling Tug
BOP Blow Out Preventer
CSV Construction Support Vessel
CHARM Chemical Hazard Assessment and Risk Management
DP Dynamic Positioning
DSV Dive Support Vessel
FPSO Floating production, Storage and Offloading Vessel
LMRP Lower Marine Riser Package
MMO Marine Mammal Observers
MODU Mobile Offshore Drilling Unit
MSDS Material Safety Data Sheet
MWA Mid Water Arch
NZ EPA New Zealand Environmental Protection Agency
NORM Naturally Occurring Radioactive Materials
P&A Plug & Abandon
ROV Remotely Operated Vehicle
SSI Subsea Infrastructure
SURF Subsea, Umbilical, Risers and Flowlines
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1 Phase 2 SSI Decommissioning and Removal The Environmental Protection Agency of New Zealand has contracted Intecsea to perform a technical review the removal of the Subsea infrastructure associated with the TUI oilfield including the Wells Plug & Abandonment Element of the Marine Consent and Marine Discharge Consent Application for the Decommissioning of the Tui Field, submitted on behalf of the Ministry of Business, Innovation and Employment (MBIE).
The Tui field subse sea Infrastructure (SSI) consists of the following: Production Flowlines: large diameter (~350 mm) flexible pipeline(s) used to convey production
fluids (oil, gas and water) from the wells to the FPSO.
Control Umbilicals:
Umbilical Termination Assembly (UTA)
Gas-lift lines
Gas Lift Manifold (GLM)
Gas Lift Jumpers (GLJ)
Production and gas lift Risers and Riser bases
Mid Water Arches (MWA) and Gravity Base Anchors (GBA)
Hold-back anchors:
Subsea Distribution Unit (SDU)
Hydraulic Flying Leads (HFL) and Electrical Flying Leads (EFL)
General Review Observations (SSI) Based on a review and analysis of the information contained within document number 740.30008.00000-R01-v1.0 Tui Field Decommissioning Marine Consent and Marine Discharge Consent Application 20210721, provided by MBIE, Intecsea are in agreement that there are no perceived residual risks that cannot be mitigated or managed through robust risk assessments such as Detailed Hasid Identification workshops (HAZID) that should be undertaken as part of the detailed engineering phase of the project to ensure all operations are carried out with an As Low As Reasonably Practical, ALARP, approach. The HAZID’s should be open to all relevant stakeholders such as MBIE, EPA and members of the Board of Inquiry. Risks identified include the potential for Tui 2-H flowline failure during the recovery phase and the potential for the breakup of the concrete crossing structure located at the Pateke-3H umbilical/Pateke-4H flowline crossing point.
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Intecsea / Vysus recommend that the following documents and plans are developed in the future, and are shared with the EPA and the Board of Inquiry (BOI) for review comment and approval:
An approved activity – specific Emergency Spill Response Plan (ESRP) for the proposed Subsea Infrastructure, SSI, disconnection, and removal activities.
An approved activity – specific Safety Case for the Construction support vessel or Vessels that will be deployed for the disconnection and removal activities related to the Subsea Investiture, SSI
The above documents / plans will capture critical environmental considerations, and therefore are considered essential for the safeguarding of local environment surrounding the Tui and associated Field. It is considered essential that during the course of the execution of both phase 2 and phase 3 of the project that a schedule of periodic audits and spot check are carried out on the chosen contractors to ensure adherence to the plans mentioned in the section above..
A review of the relevant section related to the disconnection of the Subsea infrastructure, SSI, and a review of the comments sheets that were produced during previous reviews have shown that there are no perceivable risks related to the disconnection and removal of the SSI and that we, general agree, with the details and conclusions contained within document 740.30008.00000-R01-v1.0 Tui Field Decommissioning Marine Consent and Marine Discharge Consent Application 20210721.
The vessel type selection and duration of the planned activities are reasonable and inline with what we, Intecsea, have experienced for similar scopes of work.
The disconnection and removal methodologies and equipment proposed all align with international norms and experience.
Description of the Project Related Vessels and Equipment Intecsea / Vysus are in agreement with the requirement to carry following unit options for the proposed SSI disconnection and removal vessels for the work scopes:
• Construction support vessel (CSV)
• Support Vessels
• Remotely Operated Vehicles (ROV’s)
2.2.1 Construction Support Vessel The class of construction support vessel included withing this section of the marine consent is consistent with the type of vessel that is commonly selected and deployed to undertake this type of work. This section of the document doesn’t go into great detail with regards to the types of equipment spreads that we would see for this type of work however it is noted that this is a high level marine consent document and not a detailed scope of work document complete with detailed operational procedures.
If the opportunity arises, and if this method is bid by the potential contractors selected for this work, there is an opportunity to a utilize a Well Intervention Vessel in the follow-on role of a Construction support
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vessel however this will be decided during the tendering phase of the project and therefore was not give a high degree of consideration during this review process
2.2.5 Remotely Operated Vehicles (ROV) Technical details of the proposed Remotely Operated vehicles, ROV, are not included in this document it has to be understood that these vehicles work on electrohydraulic systems and as such there is always a very slight risk of an unintentional hydraulic release from the vehicle.
2.3 Field Asset Deconstruction and Recovery Activities
1.5.1 Duration of Field Asset Recovery Activities The durations of the tasks noted within section 2.3 are considered to be consistent with norms that we have seen on similar project around the globe that Intecsea have been involved with at similar of greater depths that are applicable to this location. The expanded duration to 100 days, due to weather downtime, is also consistent with previous projects in locations with similar weather patterns.
1.5.2 2.3.2 Production Flowlines / risers The removal methodology outlined within this section are consistent with removal methodology we have experience in other regions for removal of similar Subsea Infrastructure with the option for reeling the flowlines to a reel or carousel on the deck of the CVS and then transferred once recovered we feel is the safest option to be considered.
Recovery of Tui 2-H flowline.
The flexible flowline has a12m split in the outer casing. The report states that the flowline has been successfully pressure tested. MBIE propose to recover the flowline in one piece and chop it into sections on the deck of the Construction Vessel. Intecsea concerned that during the lift to the surface, the sag bend of the flowline will result in high stresses in the intact layers of the flowline at the split. These high stresses may rupture the flowline and potentially freefall, in an uncontrolled manner, potentially causing seabed disturbance. It is recommended that this load case be analyzed.
1.5.3 2.3.3 Umbilicals The removal of the umbilicals, as with the removal of the Production Flowlines and Risers, is also in line with methodologies that we have experienced in other regions with similar water depths and lengths.
As noted, the fluids within the umbilicals were flushed and displaced with Transaqua HT2 prior to being disconnected from the FPSO in phase 1 of the operation. The confirmation that the umbilicals now only contain Transaqua HT2 alleviates Intecsea previous concern related to the present of hazardous chemicals.
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1.5.4 2.3.4 Gas lift Coil Tubing and risers The methodology for the disconnection, and recovery, of the Gas lift Coil tubing and associated risers is in line with previous methodologies, with regards to the required deployments of clamps by ROV to assist the removal, intecsea has encountered for this type of operation and is considered to be in line with industry standard.
As with the recovery of the risers and the umbilicals two on deck recovery methods have been presented and as with the previous sections Intecsea would recommend the method that shows the recover to a pool and the discharged to the shore based facility.
1.5.5 2.3.5 Gas-Lift Jumpers, Hydraulic Flying Leads and Electrical Flying Leads This section concentrates, rightly, on the disturbance to the seabed for the disconnection and removal of the Hydraulic Flying leads but what should also be considered, and seems to have been omitted, is the potential for discharge from cutting the Hydraulic fling leads. Other sections of the marine consent document cover that fact that the umbilicals have been flushed and left charged with Transaqua Ht2 but it is unclear if this applies to the Hydraulic Flying leads from the distribution units to the end users.
Gas-Lift Jumpers The recovery methodology, cut, lift and place in a basket, is considered to be in line with ongoing industry standards.
It is noted that for the GLJ’s for Tui-2H, 3h and Amokura -2H it has been assumed that that both ends have been disconnected during previous decommissioning activities however Intecsea would recommend that rather than making this assumption an ROV survey is undertaken to determine the exact status of the equipment.
Hydraulic and Electric Flying leads
As with the Gas Lift Jumpers The recovery methodology, cut, lift and place in a basket, is considered to be in line with ongoing industry standards however the note in the preceding section needs to be taken note of before the removal is undertaken.
1.5.6 2.3.6 Gas-Lift Manifold Except for the Mid water Arches the removal of the Gas Lift Manifold could cause the most risk from a Health and Safety point of view due to the weight of the structure, its potential for the mud mats to be “reluctant” to break free and the conditions of the original installation pad eyes. The document describes that a visual inspection of the pad eyes will be undertaken with an ROV prior to removal and that, if, the pad eyes look damaged or in poor condition an additional line would be added to the retrieval rigging. This is considered by Intecsea to be good practice. The balance of the removal procedure, as detailed within this section, is considered acceptable and in line with standard international practices.
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1.5.7 2.3.7 Midwater Arch and Gravity Base As stated above the disconnection and recovery of the mid water arches could be considered the most hazardous phase of the disconnection and recovery of the SSI due to the pre charge of gas in the Midwater arch that was required to maintain neutral buoyance during it operational life. This section of the Marine Consent and marine discharge consent application covers 3 main removal options and two alternative options.
It is recommended that due to the pre charge of gas in the Midwater arches and the risk of the buoyancy cans that make up the arches becoming detached form the hold back rigging that Option 3, Sinking of the Midwater Arch’s, would be the preferred option. Although there is the potential for more seabed disturbance caused by the landing of the arches onto the seabed this option is considered the safest of the options outlined in this section of the document.
The sections that cover the final disconnection and recovery of the mooring chains and the clump weights are considered to be good sound industry practice and are therefore considered acceptable
1.5.8 2.3.8. Production Riser Hold-back Anchors The recovery of the Production Riser Hold-back Anchor connection methodology as out lined within this section is considers to be in line with industry standards. The recovery of the anchors would be in line, and similar to, the recovery methodology that will be used by the Anchor Handling Tugs, AHT’s, that would be used to relocate or recover the anchor spreads that would be used by the MODU should a Dynamically Positioned, DP, MODU not be selected and therefore is considered as an industry standard operation.
1.5.9 2.3.9. Miscellaneous Equipment The methodology for the removal of the previously disconnected items of equipment is considered to be in line with industry standards. Its felt that although the document, through various sections states that items of Miscellaneous Equipment will be removed prior to removal of associated main equipment this may not be the case as the chosen contractor may choose to not disconnect the items of miscellaneous equipment and chose to remove at the same time as the primary equipment. This route maybe taken to reduce vessel on location time and would also be considered as totally acceptable and in line with industry standards.
The item of Miscellaneous Equipment SSI that seems, in the opinion of Intecsea, to be problematic with regards to the proposed removal technique is the concrete crossing structure located at the Pateke-3H umbilical/Pateke-4H flowline crossing point. It is stated that a recovery frame may be utilized to assist in recovery of the structure and that the frame would be placed on the seabed before having the concrete crossing structure lifted on to it and would reduce the risk of the structure breaking during recovery to surface. Its has been Intecsea experience that the removal of aged concrete structures is problematic and the risk of the structure breaking up is high. The risk of break up has been considered within the marine consent document and there is a plan to use equipment such as a crane grab to recover the broken elements of the flowline crossing the use of such tools would, in Intecsea opinion and experience, would cause considerable disturbance to the seabed and. May not, be capable of recovering of all the debris
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caused by any potential breakup of the crossing structure. It is recommended that further information be provided to the Board of Inquiry by MBIE on further mitigation of the risk identified
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2 Phase 3 Wells Plug & Abandonment The Environmental Protection Agency of New Zealand has contracted Intecsea to perform a technical review the Wells Plug & Abandonment Element of the Marine Consent and Marine Discharge Consent Application for the Decommissioning of the Tui Field, submitted on behalf of the Ministry of Business, Innovation and Employment (MBIE). MBIE is proposing to decommission the Tui field which will involve the plugging and abandoning of eight wells – which is captured as Phase 3 of the proposed decommissioning scope.
These eight (8) wells are as follows:
• Production wells: o Tui-2H; o Tui-3H (already suspended/plugged); o Amokura-2H; o Pateke-3H; o Pateke-4H;
• • Exploration wells (all already suspended/plugged): o • Tui-SW-2; o • Tieke-1; and o • Amokura-1
The Tui field also consists of other wells (Kiwi-1, Kahu-1, Tui-1, Pateke-1, Pateke-2, Taranui-1, Oi-1, and Oi-2) which have already been permanently plugged and abandoned, including removal of wellheads, and are therefore not part of the decommissioning of the Tui field.
General Review Observations Based on a review and analysis of the information provided by MBIE, Intecsea / Vysus are agreement that there are no perceived residual risks that cannot be mitigated or managed through robust risk assessment, completed by the Operator or their assigned Project Management Contractor, going forward to ensure all operations are carried out with an ALARP approach.
. The Convention for the Protection of the Marine Environment of the North-East Atlantic (the OSPAR Convention) requires all operators controlling the operation of offshore installations on the UK Continental Shelf (UKCS) should have in place an environmental management system (EMS). Having an effective EMS assists Operators in reducing their impact on the environment, as well as improving health and safety for both employees and the community. An EMS also ensures that a company's activities do not defy any environmental legislation or regulations. EMS should be designed to:
Achieve the environmental goals of the prevention and elimination of pollution from offshore sources and of the protection and conservation of the maritime area against other adverse effects of offshore activities, and
Maintain continual improvement in environmental performance
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Intecsea / Vysus appreciate that the OSPAR convention applies to the North-East Atlantic, however several international cooperation’s are in place globally to aid in environmental protection. Following the best practices and recommended requirements of the convention would aid significantly in the safeguarding of the operational environmental and should be considered for implementation for the decommissioning of the Tui Field. Intecsea / Vysus would recommend the Board of Inquiry (BOI) request a summary of the Well Operators Environmental Management Systems (EMS) be provided for review before the commencement of the proposed well abandonment operations.
Intecsea/ Vysus understand that The New Zealand Worksafe Regulations do not present any preceptive well abandonment requirements, however the regulations require wells to be designed for safe abandonment and in line with internationally accepted good practice, incorporating continual improvement in practices and technology. Intecsea are agreement with the proposed concept of following the industry recognized Oil and Gas UK (OGUK) Well Decommissioning Guidelines – Issue 6, June 2018 for the proposed workscope. These guidelines reflect the latest industry approach and encourage innovation and efficiency whilst providing a robust framework for the risk based decision-making process that should accompany any well decommissioning activity.
Intecsea / Vysus recommend that the Board of Inquiry ensure that the following documents are developed and adhered to in the future, and are shared with the EPA for review and comment:
• An approved activity – specific Emergency Spill Response Plan (ESRP) for the proposed well abandonment activities.
• An approved project specific Oil Spill Contingency Plan (OSCP)
• An approved activity – specific Safety Case for the MODUs /WIVs contracted for the proposed well abandonment activities.
The above documents / plans will capture critical environmental considerations, and therefore are considered essential for the safeguarding of local environment surrounding the Tui Field.
Intecsea/Vysus understand that the application reviewed refers to the well abandonment design being be approved by an independent well examiner1. This requirement is driven by the Health and Safety at work (Petroleum Exploration and Extraction) Regulations 2016 and further detailed in the New Zealand Worksafe Guidelines: PETROLEUM: Well operations and well examination schemes, March 2017.
It would be suggest that, the Board of Inquiry could request a copy of both the Well Examination Scheme to be followed during the proposed well abandonment operations and the relevant well design and construction reports completed by the nominated independent and competent person who carries out the well examination.
Well Examination Schemes focus on ensuring that the proposed designs, and their execution, are completed while meeting defined Well Safety-critical element (SCEs) s defined in the New Zealand Worksafe Guidelines: PETROLEUM: Well operations and well examination schemes, March 2017. Well Examination is considered a
1 (2)(i) –best practice in relation to an industry or activity; and, page 14 of executive summary.
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critical service which aids in ensuring that abandonment operations are carried out following “ALARP” principles.
Section 2.2 – Description of the Project Related Vessels, Drilling Unit and Equipment
Intecsea / Vysus are in agreement with the requirement to carry following unit options for the proposed well abandonment work scopes:
• Mobile Offshore Drilling Unit (MODU)
• A Well Intervention Vessel (WIV)
Intecsea / Vysus would like to capture that as much as both options currently offer technical viable solutions, the most conservative option is to execute a rig-based well abandonment with a MODU. This presents a robust approach to the plug and abandonment of the wells located in the Tui Field. An approach mitigates the risk of not being able to complete all the required well isolation activities using a Rigless approach (WIV) in the planned operational window.
A rig-based solution provides optimal operational flexibility, allowing for all available contingency options to be viable should the planned well plug & abandonment operations experience unforeseen events. A rig-based approach presents the lowest risk of the Project not achieving its key objectives. Key driving factors for this selection are outlined as follows:
• Location: Due to the remote location of the TUI Field, should a rig-less approach (WIV) fail to achieve safe wellbore isolation, in the planned operational window, there would be no local in country drilling units available for a short turn around call off. This would pose a significant project risk.
• Well Integrity: A thru-tubing well plug & abandonment scope, completed using a WIV, requires assurance of annular cement and casing integrity. Should any of the key required well barriers be found to be missing or inadequate, the requirement to removing the completion and /or casing tubulars may be required to achieve safe wellbore isolation.
• Environmental Protection: As above, verified well barriers (established based on industry best practices) are critical to provide long term environmental protection, particularly important when the wellhead will be severed as the final step of the well plug & abandonment process. Should a well leak post wellhead severance, the ability to remedy the situation would not be straight forward and would result in negative environmental impact.
Section 2.4 – Well Intervention Abandonment and Wellhead Recovery Activities
The following comments and observations relate to topics covered in Section 2.4 – Well Intervention Abandonment and Wellhead Recovery Activities, of the submitted application.
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For any section not captured in the following discussion, Intecsea have no safeguarding or substantiating comments for consideration.
2.3.1 Section: 2.4.2 Duration of Well Abandonment Activities Intecsea / Vysus are in agreement with a 90-day base case and 150-day worst case estimate based on the below base case estimates:
• Production well not suspended – +/-15 days to P&A
• Production well with a suspended status– +/-7 days to P&A
• Exploration well with a suspended status - +/-7 days to P&A
2.3.2 Section: 2.4.4.1 Anchored Semi-submersible MODU The submitted application states “For each of the wells the anchors would be retrieved with the assistance of support vessels, and then relocated to position the rig above the next location” and then proceeds to touch on possible option to optimize the mooring required.
Intecsea / Vysus acknowledge that the “worse-case” mooring has been presented for this application and support this approach. However, Intecsea / Vysus would encourage that shared mooring patterns be reviewed as planning progresses to minimize the requirement for seabed disturbance.
2.3.3 Section 2.4.5.1 BOP Tethering System Intecsea/ Vysus acknowledge that BOP Tethering system are an option which can be used, should any of the wellhead systems located in the Tui Field be proven to have insufficient fatigue life to allow for well abandonment operations to be safely completed.
The application contains text to suggest that this technology should be used as best practice however, Intecsea are not in agreement with this statement. In order to confirm the requirement to place this additional equipment on the seabed, it would be suggested that this requirement is backed-up with results of a specialist wellhead fatigue study and associated risk assessment. Completing a specialist wellhead fatigue study for well re-entry is considered as industry best practice.
2.3.4 Section 2.4.6 Plug and Abandonment Intecsea / Vysus understand that the application states that:
“The three exploration wells have previously been plugged and abandoned after drilling and only require the wellheads, casing and conductor to be removed 3 m below the seabed. This work may be completed with the remaining P&A work, or during the retrieval of the SSI.”
Intecsea / Vysus are in agreement that the following exploration wells meet the above statement, based on the Oil and Gas UK (OGUK) Well Decommissioning Guidelines – Issue 6, June 2018:
o Tieke-1; and
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o Amokura-1
However, it should be noted that for exploration well TUI SW-2P/2 (known as TUI-SW2) the reservoir isolation barrier (referred to as Plug 1) length is +/-300ft (110m) and this barrier has been weight tested to verify. “Plug 2” has not been set across annular cement and therefore does not present a well barrier. “Plug 1” has been placed adjacent to good 9 5/8” annular cement (verified by a cement bond log). Traditionally, industry best practice has been to place an 800ft barrier to achieve 200ft of “good” cement as a combination barrier, however the current Oil and Gas UK (OGUK) Well Decommissioning Guidelines – Issue 6, June 2018 state:
When a combination barrier is chosen to replace two barriers, it should have:
• •A cement column of typically a minimum 200 ft MD of good cement, which is considered to constitute such a permanent barrier.
• •Typically, 200 ft MD of good cement above the zone with flow potential.
• •The internal cement plugs adjacent to the annular good cement over a cumulative distance of 200 ft MD of overlap.
While plug 1 meets the above requirement and provides reservoir isolation, plug 2 does not meet this requirement.
Further information is required to demonstrate this lack of barrier does not present a long term potential leak path for well fluids and to confirm how MBIE intends to ensure that SW-2 is abandoned in alignment with the Oil and Gas UK (OGUK) Well Decommissioning Guidelines (Issue 6).
Intecsea / Vysus have observed that shallow environmental cement plugs have not been proposed for the plug and abandonment of any of the subject wells. This requirement is not explicitly stated in the Oil and Gas UK (OGUK) Well Decommissioning Guidelines (Issue 6). However, is considered as industry best practice especially when the wellhead will be severed as the final well operation.Again, it would be suggested that not setting shallow barriers is considered further by the Board of Inquiry to ensure that this does not present a long term potential leak path for well fluids. MBIE could provide further information which demonstrates that the proposed approach has been assessed to be “as low as reasonability practical” (ALARP). Consideration should be given to any shallow formation will flow potential.
2.3.5 2.4.6.1 Installation of Abandonment Cement Plugs The application states: “If the cement is tagged lower than the planned depth, then a further cement plug may be required.”
Intecsea / Vysus would suggest that this wording is reviewed upon progression of this workscope. The requirement to repeat a cement plug should be driven by meeting the minimum plug verification requirements of the industry recognized Oil and Gas UK (OGUK) Well Decommissioning Guidelines – Issue 6, June 2018.
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The application states: “Each cement plug will be carefully calculated to ensure the minimum volumes remain on the MODU/WIV once the cementing is completed”
Intecsea / Vysus would suggest that this wording is reviewed upon progression of this workscope. The volume of each cement plug should be calculated based on using the following:
Required plug length, in this case to meet the requirements of Oil and Gas UK (OGUK) Well Decommissioning Guidelines – Issue 6, June 2018
Open hole excess, to be calculated based on prognosed hole size Bottom hole temperature Fluid in the wellbore, at time of placing the cement plug
Cement chemical usage should be based on ensuring that the minimum verification requirements of the industry recognized Oil and Gas UK (OGUK) Well Decommissioning Guidelines – Issue 6, June 2018 are met, and not on maximum product usage in order to reduce onshore processing costs.
It should be noted that ensuring minimum volumes remain onboard the vessel once the cementing operations have been completed, does not necessarily result in less harmful substances being discharged into the marine environment. By mixing the maximum cement slurry volume possible, should a batch become contaminated then a greater volume of substances will be discharged into the marine environment.
2.3.6 2.4.6.3 Workover Fluids Intecsea / Vysus acknowledge this section has been updated since the draft document was issued for review, and now states “There will be no oil-based fluids used, and the environment will not be exposed to oil-based fluids as part of the well abandonment activities”.
This updated wording is now considered as ALARP.
2.3.7 2.5.3 Discharge of BOP Fluid Intecsea / Vysus support the inclusion of the Erifon HD 603 HP no dye BOP control fluid as part of the application. This is a widely used BOP control fluid, required for essential well control operations.
2.3.8 2.5.4 Discharge of Cement Additives Upon reviewing this section it was not made entirely clear that the BOP and riser will be in place for the majority of the cementing operations, this therefore results in the cementing operations being completed in a closed loop system which significantly lowers the impact on the surrounding environment.
2.3.9 7.9.3 Discharge of Hydrocarbons from a Well The application states: “The surface-controlled subsurface safety valves have been tested and are in place”.
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Intecsea understand that mechanical inserts are presented across the Annular wing valve (AWV) of the Tui-2H well, and there are also mechanical inserts which prevent the subsurface safety valves (SSSV) of the following wells being function closed: Amokura 2H, Pateke 3H and 4H wells.
Therefore, the application statement appears be incorrect as the SSSV located in the following wells cannot be functioned closed and cannot be verified well barriers: Amokura 2H, Pateke 3H and 4H. MBIE should clarify the well barriers which are in place for these wells and clearly demonstrate that these well barriers are sufficient to prevent the discharge of hydrocarbons into the marine environment.
The application states: “There are significant redundancies in the BOP (seven potential barriers in the BOP)”.
Intecsea/ Vysus agree that a BOP will provide well control with redundancies, however the number of barriers cannot be quantified without knowing the selected BOP to be used.
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3 Summary of Well Plug & Abandonment Review As part of this review, Intecsea have developed a summary analysis of the observations made. It should be noted that no observations fall into the “re-work” category outlined below.
The observations made as part of this review, have been ranked as follows
Accepted - An Accepted ranking suggests that both the data reviewed is seen to be complete and that, in the opinion of the reviewer, that appropriate design / procedures / practices have / will be implemented Obtaining answers to these questions would provide insight towards understanding the proposed activities.
Advisory - An Advisory ranking suggest that either incomplete or inaccurate data has been presented, or that, in the opinion of the reviewer, that appropriate design / procedures / practices have not been fully implemented Obtaining answers to these questions would be valuable in understanding the proposed activities
Re-Work - A Rework ranking suggest that either incomplete or inaccurate data has been presented, or that, in the opinion of the reviewer, that appropriate design / procedures / practices are not detailed. Obtaining answers to these questions is critical to understanding the proposed activities.
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Item Applicable Document reference(s) Observation
Accepted
Advisory
Re‐w
ork
Suggested follow up
1 General Comment Intecsea recommend that the following documents and plans are developed in the future, and are shared with the EPA for review and comment:
• An approved activity – specific Emergency Spill Response Plan (ESRP) for the proposed well abandonment activities.
• An approved project specific Oil Spill Contingency Plan (OSCP)
• An approved activity – specific Safety Case for the MODUs /WIVs contracted for the proposed well abandonment activities.
X EPA should request these documents be issued for their review and information as these documents will cover environmental factors and risk considerations throughout.
2 General Comment Intecsea understand that the application reviewed refers to the well abandonment design being be approved by an independent well examiner. The EPA should request a copy of this approval for completeness.
X The EPA should request a copy of this approval for completeness. The Well Examination scope ensures that the well abandonment design and execution meet the required Well Safety and Environmental criteria of the Well Operator, in alignment with the local regulations.
3 General Comment Typically, it would be expected that a summary of the Well Operators Environmental Management Systems (EMS) be provided as part of the application
X This should be requested at the first instance to ensure that the proposed operations are fully captured by the EMS to be followed. The most recent EMS certification assessment date should also be supplied, along with the accreditation held.
4 Section 2.2 – Description of the Project Related Vessels, Drilling Unit and Equipment
Intecsea recommend that the selection of the unit to perform the work scope is supported by an environmental and safety risk assessment.
X
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Item Applicable Document reference(s) Observation
Accepted
Advisory
Re‐w
ork
Suggested follow up
5 Section: 2.4.4.1 Anchored Semi‐submersible MODU
Intecsea acknowledge that the “worse‐case” mooring has been presented for this application and support this approach. However, Intescea would encourage that shared mooring patterns be reviewed as planning progresses to minimize the requirement for seabed disturbance.
X
6 Section 2.4.5.1 BOP Tethering System Page 13 of the Application contains text to suggest that this technology should be used as best practice however, Intecsea are not in agreement with this statement. In order to confirm the requirement to place this additional equipment on the seabed, it would be suggested that this requirement is backed‐up with results of a specialist wellhead fatigue study and associated risk assessment.
X The MBIE should complete a specialist wellhead fatigue study for well re‐entry is considered as industry best practice. Should this study
demonstrate that tethering is required, this should be presented to the EPA for approval.
7 Section 2.4.6 Plug and Abandonment Plug 2 of exploration well TUI SW‐2P/2 does not comply with the current Oil and Gas UK (OGUK) Well Decommissioning Guidelines – Issue 6, June 2018.
X In order to demonstrate this lack of barrier does not present a long term potential leak path for well fluids, MBIE should present a Detailed Risk Assessment which demonstrates that the proposed approach has been assessed to be “as low as reasonability practical” (ALARP).
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Item Applicable Document reference(s) Observation
Accepted
Advisory
Re‐w
ork
Suggested follow up
8 Section 2.4.6 Plug and Abandonment Intecsea have observed that shallow environmental cement plugs have not been proposed for the plug and abandonment of any of the subject wells. This requirement is not explicated stated in the Oil and Gas UK (OGUK) Well Decommissioning Guidelines, However, is considered as industry best practice especially when the wellhead will be severed as the final well operation.
X It would be suggested that not setting shallow barriers is risk assessed to ensure that this does not present a long term potential leak path for well fluids, MBIE should present a Detailed Risk Assessment which demonstrates that the proposed approach has been assessed to be “as low as reasonability practical” (ALARP). Consideration should be given to any shallow formation will flow potential.
9 2.4.6.1 Installation of Abandonment Cement Plugs
The application states: “If the cement is tagged lower than the planned depth, then a further cement plug may be required.” Intecsea would suggest that this wording is reviewed upon progression of this workscope as a plug can be tagged lower than except but still meet the regulatory requirements. Therefore, a repeat plug may not be needed – therefore lowering chemical usage.
X The requirement to repeat a cement plug should be driven by meeting the minimum plug verification requirements of the industry recognized Oil and Gas UK (OGUK) Well Decommissioning Guidelines – Issue 6, June 2018. This may result in additional chemicals not being required while still meeting the requirements with regards to well barriers.
10 2.4.6.1 Installation of Abandonment Cement Plugs
The application states: “Each cement plug will be carefully calculated to ensure the minimum volumes remain on the MODU/WIV once the cementing is completed”
X The volume of each cement plug should be calculated based on using the optimal bulks in order to achieve the minimum plug verification requirements of the industry recognized Oil and Gas UK (OGUK) Well Decommissioning Guidelines – Issue 6, June 2018, and not on maximum product usage in order to reduce onshore processing costs.
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Item Applicable Document reference(s) Observation
Accepted
Advisory
Re‐w
ork
Suggested follow up
Intecsea would suggest that this wording is reviewed upon progression of this workscope.
11 Section 7.9.3 Discharge of Hydrocarbons from a Well
The application states: “The surface‐controlled subsurface safety valves have been tested and are in place”. Intecsea understand that mechanical inserts are presented across the Annular wing valve (AWV) of the Tui‐2H well, and there are also mechanical inserts which prevent the subsurface safety valves (SSSV) of the following wells being function closed: Amokura 2H, Pateke 3H and 4H wells.
X This statement required to be reviewed and confirmed to ensure this risk assessment is correct.
12 Section 7.9.3 Discharge of Hydrocarbons from a Well
The application states: “There are significant redundancies in the BOP (seven potential barriers in the BOP)”. Intecsea agree that a BOP will provide well control with redundancies, however the number of barriers cannot be quantified without knowing the selected BOP to be used.
X No direct follow up needed.
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4 Discharges Associated with Decommissioning Activities
2.5 General As this section states there will be unavoidable discharges of certain harmful chemicals and potential hydrocarbons the following comments cover these potential discharges
4.1.1 2.5.1 Discharge of Biocide Inhibited Seawater As stated in this section of the document the flow lines have been dosed with BE-9 Biocide. Due to the proposed removal methods the discharge of the Biocide into the water column is deemed to be unavoidable and therefore is deemed to be acceptable and inline with industry standards.
4.1.2 2.5.2 Discharge of Residual Hydrocarbons Prior to the disconnection and removal of the FPSO the flowlines and risers were flushed of Hydrocarbons The calculations estimate 1.1 barrels of crude oil leaking into the sea during the lift. The calculations use conservative assumptions for efficiency of flushing and rate of flow of crude oil during the lift based on industry experience. The conservative calculations start from a percentage of crude oil in the pipeline before flushing of between 0.7 and 3.2. If these crude oil percentage numbers (0.7 to 3.2) are in error by a factor of ten, then about 10 barrels of oil would leak into the water column. A factor of ten would be unbelievable as the flowlines were flushed in accordance with best industry practice by experienced contractors
IMPORTANT: Do not delete this section break
Document Title IntecseaCurrent Rev No.: Document number
Document Title IntecseaCurrent Rev No.: Document number
A.1
