HPHT CAPPING STACKS AND NEW TECHNOLOGY FOR SUBSEA WELL CONTROL. December 3, 2014 Presenter: Mike Cargol

Transcription

1 HPHT CAPPING STACKS AND NEW TECHNOLOGY FOR SUBSEA WELL CONTROL December 3, 2014 Presenter: Mike Cargol

2 Agenda Development Update HPHT Capping Stack Mudline Closure Device Divert and Flow System Well Kill Manifold

3 Global Response Equipment Footprint Alaska Russian Arctic Norway GoM Singapore Brazil South Africa

4 HPHT Capping Stacks

5 HPHT Capping Stack Development Basis for Design Dual Functional Barrier philosophy Pressure: 20,000psi (1,379bar) Temperature: Min. Ambient: 32 F (0 C) Max. Design: 350 F (177 C) Water Depth: 10,000fsw Flow Rate: 300kbopd / 685 GOR CO2: 10% H2S: 500ppm

6 Design References No: Standard Title 1 API 17D / ISO Specification for Subsea Wellhead and Christmas Tree Equipment 3 API 6A / ISO Specification for Wellhead and Christmas Tree Equipment 4 API 16A / ISO Specification for Drill Through Equipment 5 API 17A / ISO Subsea Production Equipment 6 API 17TR8 High Pressure High Temperature Design Guidelines 7 API 17W Recommended Practice for Subsea Capping Stacks 8 API 14D / ISO Specification for wellhead surface safety valves and under water safety valves for offshore service 9 API RP 2A WSD Recommended Practice for Planning, Designing and Constructing Fixed Offshore Platforms Working Stress Design 10 API RP53 Recommended Practices for Blowout Prevention Equipment Systems for Drilling Wells 11 DNV RP B401 (2005) Cathodic Protection Design

7 Proposed Designs Conventional Ram Type: 18-3/4 Ram based center bore with 4x 5-1/8 outlets utilizing gate valves Conventional Valve Type: 5-1/18 Valve based center bore with 4x 5-1/8 outlets utilizing gate valves Unconventional Valve Type: NO center passage with 4x 5-1/8 outlets utilizing gate valves

8 Conventional Capping Stack - Ram vs. Valve Center Bore

9 Ram Based Conventional Design 18-3/4 Center Bore with Dual Ram Type Barriers 4x 5-1/8 outlets w/ Dual Gate Type Barriers Outlets can be configured for Soft Shut-In with Chokes for Flowback connectors Pros: Full bore access for re-entry Comfort factor with drilling community Cons: Size and Weight (133ton) Ram technology not fully matured for 20k or temperatures above 350F Elastomeric sealing technology Hydraulic requirements

10 Examples of Ram Based Capping Stacks 18 ¾ 15,000 psi MWCC 18 ¾ 15,000 psi HWCG 18 ¾ 15,000 psi OSRL

11 Valve Based (VB1-Conventional) Conventional Design 5-1/8 Center Bore with Dual Gate Type Barriers 4x 5-1/8 outlets w/ Dual Gate Type Barriers Outlets can be configured for Soft Shut-In with Chokes for Flowback connectors Pros: Full bore access for re-entry (CT) Proven Technology with Gate Type Valves (20k and +350F) Metal to Metal sealing surfaces Minimal Hydraulic requirements Cons: Limited Re-entry capability Same size as Ram Type with Reduced Weight of 95 ton

12 Example of Valve Based Capping Stacks 7 1/16 10,000 psi OSRL

13 Valve Based (VB2-Tapered Block) Un Conventional Design No Center Bore 4x 5-1/8 outlets w/ Dual Gate Type Barriers Outlets can be configured for Soft Shut-In with Chokes for Flowback connectors Pros: Smallest and Lightest Weight Stack (80tons) Proven Technology with Gate Type Valves (20k and +350F) Metal to Metal sealing surfaces Minimal Hydraulic requirements Improved flow characteristics for installation and flowback Cons: No Reentry Capability

14 Analysis Performed CFD analysis for landing/up force 300kbopd, 685GOR 245fsw (75m) Erosion and Flow modeling 330kbpd, 685 GOR Particle size of 150 micron and sand 6lb/1,000 bbl.) Structural Analysis Containment tie-in for flowback operations

15 Evaluation Results

16 Estimated Delivery Q All components excluding 20K Ram body and H4 Connector completed in 2016.

17 MUDLINE CLOSURE DEVICE

18 MCD Placement

19 Mudline Closure Device (MCD) The MCD can be used in combination with a jack-up rig or MODU; with surface or subsea BOP to provide immediate well control options in the event of an incident or failure of the BOP system, riser or other surface equipment. The system gets installed below the BOP as a secondary safety device and pre positioned capping stack This device/system provides for a reduction in risk to the operational platform and personnel as well as a significant reduction in response time resulting in less barrels of oil to the environment and a reduced cost of response.

20 MCD Operation (Well Control) Should a well control incident arise that the rig BOP stack can not handle MCD can be operated from drilling floor via acoustic control MCD can be operated via portable acoustic system from a vessel of opportunity MCD has been designed to shear: 6 5/8 S-135 drill pipe (27 lb/ft) 10 ¾ P-110 casing (65 lb/ft) 9 7/8 SM125S casing (62 lb/ft) Wireline and seal

21 MCD System complete with Subsea Accumulator Modules (SAM)

22 MCD BOP Interface Stack-Up Test

23 MCD Offshore Deployment

24 When Capping May Not Be Feasible

25 Divert / Flow Control

26 System Overview The Divert/Flow Control (DFC) System is a preinstalled flow diversion system in the event well shut-in can not be achieved. The DFC is installed prior to drilling operations using a single field support vessel. Pre-installation brings response time during a well control incident from days or weeks to mere minutes. Once installed, the DFC system stands ready to enable the following operations: Subsea flow diversion Surface flaring Surface containment

27 Why DFC? To provide seabed shut-in and flow diversion capability for MODUs featuring both subsea and surface BOP stacks Especially helpful in remote drilling where mobilizing response operations can be difficult and delayed MCD provides shut-in capability DFC provides divert/flow capability Enables re-boarding the rig Re-entering the well to perform a kill Centralized Oil Collection for Oil Spill Response Operations

28 Divert/Flow Control Capability For well control events where the well can not be shut-in Well bore integrity breached Release of gas on the drilling rig DFC is a pre-installed solution to relieve well bore pressure Diverted away from the rig Outside SIMOPS exclusion zone Enables top-kill, flaring, or other intervention options

29 MUDLINE CLOSURE DEVICE & DIVERTER/FLARE FOR J/U DIVERTER FLARE 500m DIVERTER LINE MUDLINE CLOSURE DEVICE & SAM 29

30 MUDLINE CLOSURE DEVICE & DIVERTER/FLARE FOR J/U 30 30

31 MUDLINE CLOSURE DEVICE & DIVERTER/FLARE FOR J/U OIL SPILL RESPONSE DIVERTER FLARE 500m DIVERTER LINE MUDLINE CLOSURE DEVICE & SAM 31

32 Divert / Flow Control System High Pressure Riser Subsea Divert/Flow Control Connection Subsea Divert/Flow Control Line MCD 15,000 PSI Wellhead

33 Divert / Flow Control System Divert/Flow Control Riser Divert/Flow Control Far End Divert/Flow Control Line Divert/Flow Control Base

34 Divert / Flow Control System Flare Containment Boom Mooring Line Submerged Buoy Divert/Flow Control Riser

35 Well Kill Manifold CONCEPT

36 Well Kill Manifold Concept For use on wells when determined adequate kill rates cannot be achieved from a single vessel The Well Kill Manifold allows for sufficient pump rates to be achieved through a single relief well by manifolding multiple kill vessels into the well near the wellhead and providing a flow path through the annulus Well kill by injecting through Well Kill Manifold, down the relief well, through the formation into the flowing well at a high flow rate that forms a homogeneous slug with enough fluid head to stop flow.

37 Overview Kill vessel #1 Relief Well MODU Kill vessel #2 Sea Surface Flowing Well Seabed Flowing Wellbore Producing Reservoir Relief Wellbore Well Kill Manifold Beneath BOP

38 Well Kill Manifold Features Vertical Bore: 18 ¾ Rated Pressure: 15,000 psi Outlet passages: 2x 5 1/8 inch Injection Rate (total): 200 bpm, 1.8 to 2.0 SG, 50 cp liquid. Outlet Closure devices: Hydraulic actuated gate valves Main Bore Closure devices: Hydraulic actuated ram blocks Controls: Independent hydraulic stored energy controlled by acoustic link/selective ROV backup function

39 TRENDSETTER ENGINEERING, INC. Leader in Contemporary Subsea Solutions