SubseaDTESeminar_2011

7/26/2019 SubseaDTESeminar_2011

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P.O. Box 577Brookshire, TX 77423U.S.A

Tel: (281) 375-5515Fax: (281) 934-1600

[email protected] 9001 Certified

SUBSEA DRILL THROUGH EQUIPMENTDetailed Daily Seminar Outline

Note: The actual outline of the seminar may vary depending on instructors and new

material.

Manuals provided during the seminar are the following:

• Subsea Drill Through Equipment seminar manual

• Presentation notebook

• Industrial Fluid Power textbook

• A PETEX primer can be supplied before the seminar, upon request

During the seminar, there are many references made to various standards and regulations,including:

Primary:

• API RP (Recommended Practice) 53 3rd Edition, “Recommended Practices forBlowout Prevention Equipment Systems for Drilling Wells” (American Petroleum

Institute)

• API RP 16Q 1st Edition, “Recommended Practice for Design, Selection, Operationand Maintenance of Marine Drilling Riser Systems”.

• API Spec 16A 3rd Edition, “Specification for Drill Through Equipment ”

• API Spec 16D 2nd Edition, “Specification for Control Systems for Drilling Well

Control Equipment and Control Systems for Diverter Equipment ”

Secondary:• API Spec 16C 1st Edition, “Specification for Choke and Kill Systems”

• API Spec 16F 1st Edition, “Specification for Marine Drilling Riser Equipment ”

• API Spec 16R 1st Edition, “Specification for Marine Drilling Riser Couplings”

• API Spec 17D 1st Edition, “Specification for Subsea Wellhead and Christmas Tree

Equipment ”

• API RP 64 2nd Edition, “Recommended Practices for Diverter Systems Equipment

& Operations”

** Workshop – As time allows, a workshop on mud gas separators will be included.



WEST Subsea Drill Through Equipment Seminar of 11

INTRODUCTION

A. Safety at the seminar site, emergency exits

B. Instructor and student introductions

C. Industry overview1. How old are our rigs and where is the oil

2. When and where does downtime occur on subseaBOPs?

D. Basis from which the seminar is presented:1. Rig assessments

2. RigLore3. ITPs (Inspection and Testing Procedures)

4. Lessons Learned

E. Reliability of subsea BOP equipment

1. Infant mortality2. What is the “bathtub curve”?

F. Standards to which we assess

1. Industry standards such as API, ANSI and NACE2. Manufacturers engineering bulletins and product alerts

3. Regulatory requirements

4. WEST’s database

Section I - QUALITY MANAGEMENT

A. Industry quality systems

1. API Q1

2. Product performance reports

B. Are we a learning industry?

C. Closing product performance reports1. API Spec 16A

2. API RP 53

3. Spec. Q1

D. Are we a proactive or reactive industry?

E. When you hear equipment is “certified”, what should your response be?

Copyright© 2010 WEST Engineering Services




Section II – BASIC CONCEPTS

A. Information management

1. Know what you have

2. Know how to retrieve it

B. Torque/Preload and behavior of bolted joints1. Preload variables using torque

2. Hydraulic torque wrenches3. Fastener identification:

4. Vibration loosening

5. Embedment relaxation and creep

C. What you need to know about material properties1. API requirements

2. NPD (Norwegian Petroleum Directorate)

requirements3. Charpy “V” notch4. Hardness testing

5. NACE

D. Pressure, force, area, etc., and basic equations

E. Accumulator useable volume

Section III – WELL CONSTRUCTION –

THE BIG PICTURE

A. Drilling rig types

B. Circulating system

1. Basic flow path2. Mud pumps

3. Mud cleaning system

C. Establishing the wellhead, guide-base, andrunning casing

D. Running the BOP stack

E. Motion compensation introduction1. Drill string compensation

2. Guideline tensioning3. Riser tensioning

F. Diverter systems introduction





Section IV - BOP CONTROL SYSTEMS – HYDRAULIC

PILOTED

A. Basic components of a piloted hydraulic control system

B. Introduction to basic fluid power symbols

C. Reading and understanding hydraulic

schematics

D. BOP stack hose management

E. Subsea BOP control systems

1. Mixing system and cleanliness2. Pumping system

3. Accumulator system4. Principle of redundancy

5. Open/block/close function

F. Remote operated vehicles (ROVs)

1. ROV intervention2. ROV panel designs

3. BOP recovery systems

Section V - SURFACE MUD FLOW

NETWORKA. Systems - choke and kill manifold

1. Requirements of API RP-532. API RP-53 design and installation

instructions

a. Size and pressure ratingb. NACE MR-01-75 and hardness

c. Remote, adjustable, and fixed chokes

d. Testing, Minerals ManagementService (MMS) and API

e. Buffer tanks and vent linesf. MMS guidance

B. Shipboard high pressure piping1. Beware of the unseen

2. Elbows and bends

C. Equipment failures: Equipment checks after

taking a kick1. Gates and seats from hydraulic chokes

2. Washed spools downstream of chokes





3. Manual choke wear characteristics

4. Flow targets: Purpose, maintenance, and inspection

D. Mud gas separators (poor boy degassers)

1. Theory of operationa. Atmospheric and the pressurized type

b. Vertical vs. horizontal installationc. UK HSE (Health & Safety Executive)

guidance

2. Mud gas separator vent line sizing, and why it isimportant

3. Separator vent line sizing workshop (available)

E. Diverters

1. Purpose and application2. Sequencing of valves, regulatory requirements

3. Vetco KFDS and Hydril FS4. Testing, API, and MMS

5. Vent line sizes, API, MMS, UK HSE, and DNV

(Det Norske Veritas)

Section VI – AUXILIARY LINES &

CONNECTIONS

A. Choke and kill stabs

1. Mechanical stabs

a. Stab plate/receiver plate separationb. Visual inspection and surface finish

c. Correct testing techniques2. Cameron’s mini collet connector

B. LMRP choke and kill flex piping1. Hose and flex loops

a. Advantages/Disadvantagesb. Re-certification and failure modes

2. High-pressure hose inspection –WESTScope

C. Stack frame issues

Section VII – MARINE RISER SYSTEM

A. Telescopic joints and riser 1. General system description

2. Vetco Hughes and Cameron telescopic jointsa. Support rings

b. Packers, operating pressures, redundancy

c. Pinning/Locking techniquesd. How spiders can collapse inner barrels





e. Safety precautions while running the

BOP stack

3. Vetco, Cameron, and Shaffer risera. Dog-types and preload

b. Riser inspection and documentationc. Cracking of the pins and boxes

4. Choke and kill pinsa. Colmonoy overlays - hardness and

abrasion resistance

b. Visual examination and surface finish

c. Allowable pitting on seal surfaces5. Flange-type connectors

a. API RP-2R: Preload and design stressconsiderations

b. Hydraulic bolt tensioning

B. Clip riser

C. Riser adapters, transition subs, uniflex joint

extensions1. Upper retrievable wear bushings

2. Keyseating riser and annular BOPs

D. Ball and flex joints3. Hughes CR-1 and DR-1 ball joints

4. Vetco and Oilstates flex jointsa. Operation and components

b. Limitations

Section VIII – ANNULAR BOPs

A. Varco Shaffer®, Hydril GK, GL and GX, Cameron

Type D1. Effects of wellbore pressure

2. Operating pressures/hook-ups3. Theory of operation

4. API Spec. 16A requirements, CSO (completeshut off)

5. Testing requirements of annular elements

(sold separately) prior to delivery

B. Major equipment failures1. Milling swarf in operating chambers

2. Corrosion caused by weep holes anddissimilar metals

3. Visual inspection and acceptance testing of packing elements, drift testing





Section IX – HYDRAULIC CONNECTORS – WELLHEAD,

LMRP, Choke & Kill

A. Riser and wellhead connector models1. Vetco

2. Cameron

B. Design parameters1. Locking/Unlocking forces

2. Secondary unlocking chambers

3. Connector preload4. Lubrication or greasing

5. “Backdriving” – what is it and why do we

care?6. Predictive testing, verifying unlocking

ability

7. Stroke tests

C. Selection criterion

1. Pressure containment2. Tension capacity

3. Bending moment capacity

D. Hydrate exclusion

E. Cameron mini connectors

Section X – RAM BOPsA. CAMERON TYPE “U”, “UII” and “TL” ram

BOPs1. Components, operation and

sealing characteristics

2. Basics of ram packer sealing andoperation

3. Variable bore ramsa. Standard VBRs

b. Flexpackers

4. Shearing blind ramsa. Single piece shear rams – H2S

complianceb. API RP-53 and API

Specification 16ARequirements

5. Inspection particulars6. NACE

7. Ram BOP operating ratios

8. Bonnet bolts and sealsa. Bolt torque





b. Hydraulic tensioners

c. Seals

9. Emergency plastic packing injection systema. Advantages

b. Disadvantages

10. Wedgelocks and balancing chambers

11. TL BOPa. Special characteristics

b. Bonnet seal carrier

c. Side ram removald. ST locks, overhauling threads,

predictive testing

e. RamLocks12. Major equipment failures

a. Ram shaft packing areacorrosion

b. Wedgelock modificationsc. The benefits of operating

piston liners

13. Why do we even need hydraulicram locking systems?

B. HYDRIL Ram BOPs

1. Features2. Rams and ram cavities

d. Variable bore rams - HVRe. Replaceable seal seats

a. Hangoffb. Shear and pipe rams

c. Shear ram operation

3. Hydraulic operating systems

a. Fluid hingesb. Operating pressures

4. Multi-Position Lock (MPL)

a. Clutch assembly and locknut

b. Predictive testing

c. Lockout testing

C. NOV SHAFFER® “SL” and “SLX” RAMS1. Rams, ram cavities, doors

a. Pipe, shear, and variablebore rams

b. Cavity inspection

c. No weld cavityd. Booster assemblies

e. Door sealsf. Door hinges

2. Poslock and Multi-Lock system

a. Adjustmentb. Testing

3. UltraLock locking systema. Ultralock I





b. Ultralock II, A and B

4. ExxonMobil testing – the basis for API Spec 16A testing

Section XI – GATE VALVES

D. Failsafe valves1. Cameron type “AF”, “DF”, “FC”, and “MCK”

a. Advancement and modificationb. Seat rings, seal rings and body bushings

c. Body bushings and upstream sealsd. Balancing stems – what is a “failsafe”

valve?

e. Failures modes1) Plating separating from the gate

material2) Low-pressure testing problems

3) Spring cartridge testing

2. McEvoy valves, “EDU”a. Sealant injection system

b. Theory of operationc. Balancing stems

3. Actuator force4. WOM “Magnum” valves

a. Review sealing technique

b. Advantages of upstream and dsealing

ownstream

5. EEC valvesc. Review sealing technique

d. Compensating operator

6. Riser test valves (fail open)

Section XII - WHAT IS AN

ACCEPTABLE PRESSURE TEST?

A. Force, pressure and area1. Units of measure

B. Pressure recording devices1. Gauges and chart recorders

2. Pressure test units

C. Regulations1. MMS regulations

D. Safety

1. Safety while stump testingE. High pressure hose and fittings

1. Autoclave hoses and fittingsF. Stump or surface pressure tests





Section XIII - BOP CONTROL SYSTEMS – BASIC MUX

A. Hydril, Cameron system review

1. Difference and similarity to hydraulic-piloted systems

2. A basic description on how a MUX systemworks

B. Basic MUX components

1. Drillers control panel, toolpushers controlpanel and the CCU (central control unit)

2. Hydraulic power unit

3. MUX cable reels4. MUX control pods

C. MUX subsea control pod electrical components

1. MUX cable connectors

2. Solenoid-operated shear seal valves3. SEM (Subsea Electronic Module)4. DDV (Direct Drive Valves)

D. MUX HPU Components1. Automatic fluid mixing system

2. Triplex and quintuplex pumps3. Pressure relief valves and high pressure filters

4. Surface flowmeters

E. MUX subsea control pod hydraulic components1. SPM valves, hydraulic regulators and control circuits

2. Flowmeters

F. Subsea fluid paths

5. Subsea accumulator bottles6. Hydraulic hoses and shuttle valves

Section XIV - MOTION COMPENSATION

OVERVIEW

Drill string, riser and guideline tensionersA. Theory of operation

1. Wireline travel vs. piston stroke

2. Introduction to load variation

B. In-line and crown-mounted compensators1. Vetco (in-line)

a. Panel and controlsb. Olmstead valve

c. Air/Oil bottle

2. Maritime Hydraulics crown-mounted compensatora. Comparison, in-line vs. crown-mounted





b. Basic features

C. Riser and guideline tensioners1. Basics of operations: rod travel vs. wireline

travel2. Swept volume and load variation

Section XV - RING GASKETS AND

GROOVES

A. API end connection types1. Flange

2. Studded

3. Clamp hub

B. API Spec 6A1. Groove, gasket identification

2. Gasket, groove specification3. Inspection, tolerances, and surface finish

4. Re-use of gaskets, API RP-53

C. Gasket/Groove interactions

1. Face-to-face contact between hubs and

flanges2. Well bore pressure energizing

D. Ring gasket types

1. API’s R, RX, and BX2. Cameron’s and Vetco’s AX, CX, and VX

3. Resilient gaskets

E. “Washed-out ring grooves”

1. Rotating connections and galling2. Loss of bolt preload

3. Maintenance of bolted connections


SubseaDTESeminar_2011

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