EDP/LRP. Drill Well 20 th September 2018 Rev2 Presenter: Simon Carpenter [INPEX]

Transcription

1 EDP/LRP Drill Well 20 th September 2018 Rev2 Presenter: Simon Carpenter [INPEX]

2 Purpose & Agenda Purpose Present functional overview, discuss selection criteria & associated Drilling considerations for use of EDP/LRP systems; Provide overview on application of EDP/LRP for Ichthys project. Agenda Introduction; System overview; Well system selection criteria; Drilling department considerations; Intervention system application Ichthys Phase 1 2

3 Introduction 1. Australasian subsea LNG developments have typically featured; Large bores; High rates of production; High production temperatures; Long field life design; High RAM targets; Simple manifolds & complex XT s = Large, heavy XT s 2. Despite exceptions [POG, Gorgon phase 1, Jansz & Julimar] its safe to suggest VXT is the current established base case; 3. Since VXT enables well completion independent of XT, Operators can defer XT operations to a LWI vessel, enabling; Wider MODU selection or simplify upgrade or new build scope; Reduce MODU critical path operations; Relieve pressure on XT delivery schedule. 4. Lack of consistent LWI work in Australian waters resulting in high mob/de-mob fees and difficulty maintaining workforce engagement and experience. 5. Despite point 3. and perhaps in-spite of point 4. new EDP/LRP systems are still procured. 3

4 System Overview What is its purpose? Emergency Disconnect Package / Lower Riser Package EDP Emergency Disconnect Package LRP Lower Riser Package VXT - Vertical Xmas Tree THS Tubing Head Spool WH Wellhead Provides the required functionality for open water through tubing intervention operations either from MODU or intervention vessel Primary Well Control system for through tubing operations once Vertical Xmas Tree [VXT] is installed on a completed well and accordingly plays a key role in the Safety Case Addendum; Well isolation; Emergency disconnect; Redundancy design and function; ISO part 7 / API 17G OEM Standards Company Requirements Project Specific Requirements 4

5 System Overview Key functional design aspects to achieve its purpose? PRV Production Retainer Valve EXOV EDP Crossover Valve ARV Annulus Retainer Valve FRONT VIEW Mechanical Riser Connector (lift cap installed) REAR VIEW Workover Subsea Control Module PRV EXOV ARV EDP ROV panel including connector over-ride Umbilical stab plate Electrical connector output to XT Hydraulic connector high angle release Accumulator banks MIV SSR GSR PIV XOV AAV Hydraulic stab plate out-put to XT Accumulator banks LRP ROV panel including ram and connector over-ride PIV Production Isolation Valve SSR Shear Seal Ram GSR Grip Seal Ram MIV Methanol Isolation Valve XOV Crossover Valve AAV Annulus Access Valve Hydraulic XT connector EXAMPLE FOR 7 10KSI MONO-BORE SYSTEM WEIGHT 55,000kg DIMS (L x W x H) 4.6m x 3.5m x 6.8m 5

6 System Overview Key functional design aspects to achieve its purpose? Stacked on ENSCO E5006 XT Cart front view facing well centre Stacked on ENSCO E5006 XT Cart rear view facing STB Lower Stress Joint [LSJ] made-up and tested ready for deployment 6

7 System Overview Example of a system application plug recovery N2 UNIT SHOREBASED REMOTE SOFTWARE DIAGNOSTICS [ON CALL] SURFACE FLOW TREE RIG FLOOR MANIFOLD C/K MANIFOLD KILL HOSE RISER EMERGENCY DISCONNECT PACKAGE UMBILICAL REELER ANNULUS CIRCULATION MANIFOLD CEMENT UNIT WELL TEST PACKAGE LOWER RISER PACKAGE WELL TEST CABIN VERTICAL XMAS TREE SUBSEA SUPPLY HYDRAULIC & ELECTRICAL SURFACE CONTROL UNIT WIRELESS ROUTER OR LAN ESD EQD ESD EQD TUBING HEAD SPOOL ESD ESD DATA LINK [DHPT, SCSSV, PPTT, APTT] HYDRAULIC POWER UNIT ESD

8 Well System Selection Criteria [Drilling] As it relates to Ichthys 1. Cannot comment on original selection analysis carried out as joined in 2013 when equipment manufacture was well under way; 2. However, can offer the following observations that might support the original decision behind use of VXT system; Highly bespoke complex XT design with no established 7 10ksi 155 C system on the market; Major qualification program undertaken; Longest field life specification 40 years; Extensive QAQC / verification / validation requirements from forging level onwards; Offshore LNG contractual commitments; Major 3 rd party sub-components involved; choke, WGM, CIMV; Inherently simple and reliable completion design with inbuilt contingency i.e. PSN; Multiple drill centre phased approach; commissioning, SIMOPS. Brief discussion on how these points may apply to risk profile of HXT system 3. Can offer the following observations that might support the original decision behind use of THS system (despite the CAPEX, OPEX and greater fatigue loading); Effectively de-couples wellhead system from SPS factory integration of EFAT; Simplifies the wellhead system regarding orientation and alignment requirements; Does not require implementation of orientation interface on LLSA / BOP for TH alignment; Does not require of height elevation runs (LIT) and associated shimming; Provides a dedicated orientation helix and landing shoulder; Provides a robust annulus access system; Provides enhanced contingency in the event of major seal bore damage; The decision was also made to procure a complete open water intervention system (primary and back-up), following sides show some of the considerations undertaken by Drilling to enable its usage.

9 Drilling department consideration Scope Optimisation Purchased equipment SOS drawings identifying equipment not required during phase 1 operations

10 Drilling department consideration Scope Optimisation 7-5/8 TN-95S 33.7# Casing Landing String with Tenaris W563 connection and Tk-805 internal coating Lower Landing String Assembly Riser x-over EDP/LRP Emergency Riser Tension Management System*** Surface Flow Tree with Poly-oil Riser Sealing Mandrel and stiffener clamp*** Sliding table for upper completion operations Power frame for landing string make-up High Set Lubricator Valve Assembly ***If flow back via EDP/LRP, ERTMS, SFT & HSLV not utilised for upper completion. Lower Stress Joint 10

11 Drilling department consideration Scope Optimisation 11

12 Drilling department considerations MODU handling system E5006 STB 165T AHC Knuckle Boom Crane Mock XT trial in shipyard XT/LRP/EDP stacked up in XT cart Mock EDP/LRP trial in shipyard EDP/LRP stacked in XT cart LRP under gantry and EDP on subsea support stand EDP/LRP under gantry crane

13 Drilling department consideration Mobilisation Planning Utilising commercial vessel to mobilise XT s to Darwin on its return trip Purpose built grillage removable / re-installable grillage designed for ASHV XT s collected from Darwin due to Broome wharf capacity. STB crane upgrade to NOV 165T knuckle boom with AHC mode off-loading XT s Deck integrated subsea equipment support stands x 2 allowing maintenance and cyclone storage with-out lashings Deployment of XT via AHC crane allowing ROV to carry out, lock flush and test operations off-line during BOP recovery. 13

14 Drilling department considerations MODU deck management Making the most of available space; 1 x Tubing Head Spool 2 x VXT s 1 x LRP 1x EDP Long term dedicated position for HPU and SCU 14

15 Drilling department consideration Operational Efficiency Un-latch BOP with HOP tool and MRT support, install THS via AHC crane re-land and test BOP Rig-down diverter, unlatch BOP & install XT with AHC crane and recover BOP Deploy EDP/LRP on casing landing string and install on XT. 15

16 Drilling department consideration Operational Efficiency ROV fluid injection system for sea-water flushing AHC deployment of XT AHC deployment of THS BDC-1C-06 XT installation timing analysis XT deployment plate PDHG verification with-out IWOCS Critical path (Rig Kedge) Critical path (XT) Off-line NPT Off-line NPT Hi-flow ROV pump system 16

17 Drilling department consideration Operational Efficiency XT Installation, Flushing & Testing Operations ENSCO E5006 BDC-1B-01 FLX Frame recovered off-line, no additional kedge required from BOP recovery position. BDC-1C-02 No kedge required for FLX frame. STB crane could reach whilst BOP connected to BDC-1C-06. Frame recovered offline. BDC-1C-06 Kedge for XT & FLX frame. Frame recovered off-line. THS preparation off-line prior to disconnect BOP on BDC-1C-01. Off-line NPT NPT Off-line BDC-1C-01 Kedge for XT & FLX frame. Frame recovered off-line. THS preparation concurrent to disconnecting & stowing BOP control lines, boost line, choke line and kill line. BDC-4-04 Kedge for XT. FLX frame planned recovery post BDC-4-02 during BWM. Critical Path (XT) Critical Path (Rig kedge) BDC-4-03 ST1 Kedge for XT. FLX frame planned recovery post BDC-4-02 during BWM. STB crane should reach while BOP connected to BDC-1C BDC-1B-01 BDC-1C-02 BDC-1C-06 BDC-1C-01 BDC-4-04 BDC-4-03ST1 THS Preparation work carried out off-line

18 Drilling department considerations Continuous Improvement Initial Performance Suspension plugs recovery from BDC-5-04ST1 and BDC-5-05 through EDP/LRP was proposed. Utilise rig time after completion of BDC-5-05 and before rig stand-by. Cancel LWI campaign. Demonstrate EDP/LRP operation capability on ENSCO5006 Decision was made on 12/Oct, equipment was mobilized on the rig and operation started from 01/Nov. Plan: Actual: NPT: 14.9days 11.8days 1.8days 18

19 Drilling department considerations Continuous Improvement Lessons Learned INPEX Drilling AOR Process After completion of each major operation [typically defined by SID] an AOR shall be held offshore with all personnel involved in the job. The AOR shall be chaired by Company Operations Engineer and shall cover and record the following; Operations summary; Any MOC s raised; Well Acceptance Criteria [WAC] achieved; Breakdown of operational steps with times including; Budgeted time; Actual time; Non Productive Time [NPT]; Best time to date; Delta to best. What went well; What didn t go so well; Recommendation list; Comparison with wells to date [productive time and NPT]; Comparison with wells to date [productive time activity breakdown]. The AOR must be done as soon as possible after the operation has been completed in order to be of maximum benefit. Obviously there are always personnel availability constraints that need to be taken into account. The AOR must be done with the relevant INPEX, drilling and service contractor personnel who were involved in the operation. The AOR must be sent to the agreed distribution list. The AOR should include recommendations, not actions, as they must be reviewed and agreed by the onshore team; DS and relevant engineers. AOR s shall be formally issued to Drilling team for review and follow up on recommendations and confirm any actions required. Actions may range from relatively simple procedural revisions through to bespoke modification of equipment or MOC to well program. After Action Review [AAR] Onshore action list example first time post usage of EDP/LRP Extract from our Detailed Completion Procedures key message a robust continuous improvement system is critical

20 Drilling department considerations Continuous Improvement Well Just Completed Well just completed (2 nd well with flow-back via EDP)

21 Intervention System Application Ichthys Phase 1 Well system basis 1. 7 mono-bore 10,000psi 155 C VXT with FCM and THS was selected; 2. An entire intervention package (primary & back-up) was procured as part of the SPS Contract under the following assumptions; Upper completion would be deployed on a dedicated riser system with a BOP spanner joint and simplified surface assembly; Well flow-backs would be carried out via EDP/LRP as an open water operation; A weak link would be utilised above the lower stress joint as a safety device; Top tension would be applied via MRT and blocks; What actually occurred 1. Casing was sourced to replace the dedicated riser system with x-over to LSJ; 2. Rental SSTT package was sourced to enable pressure testing of landing string prior to circulating well to underbalance, and provide disconnect in storm events with-out reliance on slick-line to establish barriers; 3. SSTT package was specified to meet FTHT requirements as contingency in the event of late XT s, late EDP/LRP or any fundamental technical issued delaying their usage; 4. Decision note was issued to remove weak link joint, upper stress joint and tension joint and introduce a ERTPS to manage riser tension in the event of CMC failure; 5. Riser analysis was carried oy to validate use of casing as in riser and open water CWOR; 6. MODU upgrade scope was engineered to cover XT deployment on wire [AHC crane] or through moon-pool with EDP/LRP and storage of equipment spread including IWOCS, SCU & HPU; 7. THS s and VXT s were delivered and ready in time for well completions (commencing October 2015) but EDP/LRP/IWOCS was not available; 8. Well construction including completion and flow back continued with VXT s being installed on each well via E5006 AHC crane post leaving upper completion suspended with 2 x mechanical barriers above SCSSV; 21

22 Intervention System Application Ichthys Phase 1 What actually occurred (continued) 9. LWI vessel was contracted in Q and carried out a 10 week campaign 9 months later (starting Aug 2017) to recover slick-line plugs from 12 wells across 3 x Drill Centres for hand-over to commissioning 10. EDP/LRP/IWOCS became available October 2017 at which point 13 wells had been completed and flowed back to E5006 via SSTT / casing landing string system; 11. Decision was made to utilise LRP/EDP with remaining rig time prior to cyclone season stand-by to recover plugs from 2 x wells and campaign was successfully completed in 12 days starting 1 Nov 2017; 12. Decision was them made for remaining phase one wells to be flowed back via EDP/LRP based upon; Simplification and associated critical time reduction of the upper completion operation no N2 suspension and reduced E-red to remove slick-line, no HSLV, SFT or ERTPS; Negate requirement for LWI intervention for plug recovery; 13. Post cyclone standby period 2 x wells to date have been completed and flowed back via EDP/LRP. 14. In parallel to the tail end of phase one well construction operations, FEED and tendering activities are progressing for phase 2a SPS scope. 15. Current Phase 2a assumptions***; Company owned EDP/LRP system will be utilised for well flow-back (irrespective of Phase 2a VXT supplier) if VXT s are available and will be utilised for plug recovery if XT s are available for batch set during a drill centre operation (if not ready for each well); SSTT system will be contracted for phase 2a as upper completion risk mitigation and provide contingency for VXT s not being available. ***This premise will be further analysed based on cost of ownership assumptions for ongoing storage, maintenance, repair and recertification of the Company owned EDP/LRP/IWOCS for use during Phase 2a compared with LWI. 22