edp/lrp - drillsafe · subsea supply – hydraulic & electrical . surface control unit ....

EDP/LRP

Drill Well 20th September 2018 Rev2 Presenter: Simon Carpenter [INPEX]

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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

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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

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.

= Large, heavy XT’s

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System Overview

What is its purpose?

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;

VXT - Vertical Xmas Tree

THS – Tubing Head Spool

WH – Wellhead

LRP – Lower Riser Package

EDP – Emergency Disconnect Package

Emergency Disconnect Package / Lower Riser Package

ISO – 13628 part 7 / API 17G OEM Standards Company Requirements Project Specific Requirements

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EXOV ARV

PIV

PRV

AAV

XOV GSR

SSR MIV

PRV – Production Retainer Valve EXOV – EDP Crossover Valve ARV – Annulus Retainer Valve

PIV – Production Isolation Valve SSR – Shear Seal Ram GSR – Grip Seal Ram MIV – Methanol Isolation Valve XOV – Crossover Valve AAV – Annulus Access Valve

System Overview

Key functional design aspects to achieve its purpose?

Hydraulic XT connector

Hydraulic stab plate out-put to

XT

Mechanical Riser Connector (lift cap installed)

Workover Subsea Control Module

LRP ROV panel including ram and connector over-ride

EDP ROV panel

including connector

over-ride Umbilical stab plate

Hydraulic connector – high

angle release

Electrical connector out-

put to XT

Accumulator banks

Accumulator banks

FRONT VIEW REAR VIEW

EXAMPLE FOR 7” 10KSI MONO-BORE SYSTEM WEIGHT – 55,000kg DIMS (L x W x H) – 4.6m x 3.5m x 6.8m

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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

CEMENT UNIT

WELL TEST PACKAGE

SURFACE FLOW TREE

RISER

EMERGENCY DISCONNECT

PACKAGE

LOWER RISER

PACKAGE

VERTICAL XMAS TREE

TUBING HEAD

SPOOL

UMBILICAL REELER

ANNULUS CIRCULATION

MANIFOLD

SUBSEA SUPPLY – HYDRAULIC &

ELECTRICAL

SURFACE CONTROL UNIT

HYDRAULIC POWER UNIT

KILL HOSE

System Overview

Example of a system application – plug recovery

ESD

ESD

ESD

ESD EQD

ESD EQD

WIRELESS ROUTER OR LAN

SHOREBASED REMOTE SOFTWARE DIAGNOSTICS

[ON CALL]

WELL TEST CABIN

DATA LINK [DHPT, SCSSV, PPTT, APTT]

N2 UNIT

C/K MANIFOLD

RIG FLOOR MANIFOLD

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 3rd 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.

Drilling department consideration

Scope Optimisation

Purchased equipment SOS drawings identifying equipment not required during phase 1 operations

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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

Lower Stress Joint

Lower Landing String Assembly Riser x-over

EDP/LRP

High Set Lubricator Valve

Assembly

7-5/8” TN-95S 33.7# Casing Landing String with Tenaris W563 connection and Tk-805 internal coating

***If flow back via EDP/LRP, ERTMS, SFT & HSLV not utilised for upper completion.


Scope Optimisation

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Scope Optimisation

Mock XT trial in shipyard Mock EDP/LRP trial in shipyard XT/LRP/EDP stacked up in XT cart

EDP/LRP stacked in XT cart EDP/LRP under gantry crane LRP under gantry and EDP on subsea support stand

E5006 STB 165T AHC Knuckle Boom Crane

Drilling department considerations

MODU handling system

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Utilising commercial vessel to mobilise XT’s to Darwin on its return trip

Purpose built grillage removable / re-installable grillage designed for ASHV

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

XT’s collected from Darwin due to Broome wharf capacity.

Deployment of XT via AHC crane allowing ROV to carry out, lock flush and test operations off-line during BOP recovery.


Mobilisation Planning

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Long term dedicated position for HPU and SCU

Making the most of available space; • 1 x Tubing Head Spool • 2 x VXT’s • 1 x LRP • 1x EDP


MODU deck management

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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.

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4.25 2.49

26.84

1 2.58

Critical path (Rig Kedge)

Critical path (XT)

Off-line

NPT

Off-line NPT

BDC-1C-06

• Hi-flow ROV pump system

ROV fluid injection system for sea-water flushing

AHC deployment of XT

XT deployment plate

AHC deployment of THS

XT installation timing analysis

PDHG verification with-out IWOCS



2.75 1.83 4.25 5.75 1.5 3.25

11.39 6.67 2.49

2.75 4.39

4.91

48.08

30.83 26.84

19.67 17.91

19.86

2.92

1

0.1

31.17

1.5 2.58

3.42 1.09

6.28

0

20

40

60

80

100

120

BDC-1B-01 BDC-1C-02 BDC-1C-06 BDC-1C-01 BDC-4-04 BDC-4-03ST1

XT Installation, Flushing & Testing Operations – ENSCO E5006

Off-line NPT

NPT

Off-line

Critical Path (XT)

Critical Path (Rigkedge)

BDC-4-04 Kedge for XT. FLX frame planned recovery post BDC-4-02 during BWM.

BDC-1B-01 FLX Frame recovered off-line, no additional kedge required from BOP recovery position.

BDC-1C-06 Kedge for XT & FLX frame. Frame recovered off-line. THS preparation off-line prior to disconnect BOP on BDC-1C-01.

BDC-1C-02 No kedge required for FLX frame. STB crane could reach whilst BOP connected to BDC-1C-06. Frame recovered 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-4-03 ST1 Kedge for XT. FLX frame planned recovery post BDC-4-02 during BWM. STB crane should reach while BOP connected to BDC-1C-02.

THS Preparation work carried out off-line

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• 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: 14.9days Actual: 11.8days NPT: 1.8days


Continuous Improvement – Initial Performance


Continuous Improvement – Lessons Learned

After Action Review [AAR] Onshore action list

example first time post usage of EDP/LRP

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.

INPEX Drilling AOR Process

Extract from our Detailed Completion Procedures – key message…a robust continuous improvement system is critical


Continuous Improvement – Well Just Completed

Well just completed (2nd well with flow-back via EDP)

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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;

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What actually occurred (continued) 9. LWI vessel was contracted in Q4 2016 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.

Intervention System Application

Ichthys Phase 1

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