PROVIDE A SECOND LIFE FOR THE DRAUGEN FIELD Draugen, Subsea - - PowerPoint PPT Presentation

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PROVIDE A SECOND LIFE FOR THE DRAUGEN FIELD Draugen, Subsea - - PowerPoint PPT Presentation

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HO HOW S SUBSEA T TECHN HNOLOGY I IS ABLE T TO PROVIDE A SECOND LIFE FOR THE DRAUGEN FIELD Draugen, Subsea Boosting and Industry Initiatives Use this area for cover image (height 6.5cm, width 8cm) Richard Tong Senior Subsea

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SLIDE 1

HO HOW S SUBSEA T TECHN HNOLOGY I IS ABLE T TO PROVIDE A “SECOND” LIFE FOR THE DRAUGEN FIELD

Draugen, Subsea Boosting and Industry Initiatives

Richard Tong Senior Subsea Processing Engineer

1 21 April 2016

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SLIDE 2

AGENDA

1.0 Introduction to Draugen 2.0 Draugen Infill Project 3.0 Subsea Pumping System

  • Scope of Supply - Testing - Technology Qualification API 17N

4.0 Technology & Industry Initiatives on Subsea Boosting 5.0 Field Screening of Subsea Boosting

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Courtesy of: Heine Schjølberg

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SLIDE 3

History and Introduction to Draugen

DRAUGEN

1.0

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HI HISTORY RY O OF DRAUGEN

  • First and only Single-leg GBS platform
  • Low number of wells, due to successful production

strategy

  • Continuous project activity and investments underway to

make Draugen a high integrity mature producer

  • Robust and sustainable design; fit-for-purpose for

potential future 3rd party Tie- ins

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SLIDE 5

HI HISTORY RY O OF DRAUGEN

Draugen Field Résumé

 Field Properties

 Located in Haltenbanken area, 140km North of Kristiansund  Discovered in 1984 and production start 19.10.1993  Partners: A/S Norske Shell (Operator, 44.56%),

Petoro AS (47.88%), VNG (7.56%)

 Water Depth ~ 250-280 m  Peak Production 225 000 bbl/day  High uptime- high recovery

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SLIDE 6

21 April 2016

HI HISTORY RY O OF DRAUGEN

Draugen Field Résumé (continued)

 Geological / Geophysical Properties

 Main reservoir in sandstone: Rogn and Garn Formations of

Late and Middle Jurassic ages respectively

 “World-Class” Reservoir at 1600m depth  Produced by pressure maintenance from water injection and

aquifer support; gas lift used

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SLIDE 7

DRAUGEN

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SLIDE 8

Project Scope

DRAUGEN I INFILL PROJECT

2.0

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SLIDE 9

DRAUGEN I INFILL DRILLING C CAMPAIGN

9 21 April 2016

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SLIDE 10

DRAUGEN I INFILL DRILLING C CAMPAIGN

Draugen Infill Drilling Campaign

 4x New Subsea Production Wells  Subsea Boosting Pump  Subsea Tee Manifold @ Rogn South  19 km of New Flowlines  11 km of New Umbilicals  52 tie-ins  113 GRP Covers  70 Concrete Mattresses  245 000 m3 Rock Installation  11 000 m3 Rock Removal

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SLIDE 11

HY HYDRATE P PLUG RISK FOR SUBSEA FLOWLINES

Ris isk Descrip iption ion: Cause - Lift gas circulated in flowlines Potential Event - At an unexpected long shutdown, a hydrate plug may form Consequence - Loss of flowline, i.e. potential loss of production Ris isked Value = Cost x Probability

Assumptions-Information:

  • The plug can only be remediated by flowline replacement
  • Gas lift will have to be used in the future to maintain the production

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SLIDE 12

HY HYDRATE F FORMATION RISK

 Hydrate formation risk was a key factor towards driving concept

towards subsea pump

 Experimental and theoretical work indicates hydrate formation is

possible with Draugen oil. Risk increases with introduction of lift gas

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SLIDE 13

DRAUGEN I INFILL DRILLING C CAMPAIGN

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Advantages of Framo Dual-Pump Station (FDS)

 Subsea Boosting Pump Station

 Reduces back pressure “seen” by wells =

increased oil recovery ~70%

 Accelerated End-of-Field Life production  Increased efficiency as water cut increases

  • ver time

 Reduces risk of hydrate formation – no

need for continuous gas lift

 Allow field start-up  Offers metering of new wells coming on-

stream

 Future expansion flexibility

13 21 April 2016

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SLIDE 14

3.1 SMUBS 1993 3.2 Scope of Supply 3.3 Testing

DRAUGEN S SUBSEA PUMPING SYSTEM

3.0

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WORLD’S FIRST MULTIPHASE SUBSEA PUMP A/S Norske Shell D Draugen F Fie ield

Contract Award: 1990 1990 Sales: FMC K Kongsberg, N , Norway Pump Integration: FMC K Kongsberg, N , Norway Pump Fabrication: Framo, , Norway Host Type: Draugen GBS Platform Contract Type: EPC Water Depth: 28 280 0 m ( (92 920 0 ft) The Draugen Subsea Well Facilities Contract was the largest subsea EPC contract in Norway at the time. All subsea installations were designed for diverless installation, operation and maintenance. The seabed pumps (i.e. system integration of FRAMO pumps) were the world’s first commercial multi-phase pump installation. The pump was installed in 1993. It ran sucessfully from 1995 for 12.2 months (1000 operating hours) and was decomissioned and abandoned due to change in water injection strategy. Oil and Gas Journal: “Norske Shell has let a $100-million contract to Framo Engineering for a complete subsea multiphase booster pump system for Draugen oil field offshore Norway, where the world’s first such system was installed in 1994.”

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SLIDE 16

SMUBS

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SLIDE 17

DRAUGEN SUBSEA PUMP SYSTEM

SCOPE OF SUPPLY

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DRAUGEN INFILL PROJECT PUMPING SYSTEM

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  • Reduces back pressure “seen” by wells = increased oil recovery
  • Accelerated end-of-field life production
  • Avoid continuous gas lift, reduces hydrate formation risk
  • Offers metering of new wells coming on stream & expansion flexibility
  • Tie-back distance (To Draugen): ~4 km (12” flexible)
  • Ambient Temperature (seawater): 6 – 8 °C
  • Design temperature (flowlines):

75 °C

  • Design pressure: 220 bar
  • Number of Pumps: 2
  • Motor Rating: 2300 kW
  • Maximum dP: 50 bar

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SLIDE 19

PFD

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SLIDE 20

HE HELICO-AXIAL P PUMPS

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Draugen P Pump System P Parameters

  • Design pressure:

220 barg

  • Process operating temperature:

4 to 75 ºC

  • Max pump differential pressure:

50 bar

  • Pump suction pressure:

21 - 29 bara

  • Pump suction GVF:

10 - 32% (75%)

  • Pump flow rate:

643 - 855 Am3/h

  • Pump speed:

1500 – 4200 rpm

  • Pump motor shaft power:

2300 kW

  • Water Depth:

268 m

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SLIDE 22

MULTIPHA HASE P PUMP

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SLIDE 23

PUMPING SYSTEM SCOPE OF SUPPLY

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SLIDE 24

TOPSIDE - POWER CONTROL M MODULE ( (PCM)

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DRAUGEN S SUBSEA PUMP: : PROCESS CONTROL M MODULE

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PUMP STATION

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MPP1 MPP2 MPFM3 MPFM2 MPFM1 MPFM4 (dummy) Main inlet Well G-1 Well G-2 Well G-3 Well A-55 55 SCM V4, V4, retrievable choke insert

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SLIDE 27

PUMPING SYSTEM SCOPE OF SUPPLY

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Process Control Module Topside Umbilical Termination Unit Subsea Umbilical Termination Assembly

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SLIDE 28

PUMP STATION INSTALLATION

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SLIDE 29

PUMP TESTING

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SLIDE 30

TESTING

MV connector stack-up test

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SLIDE 31

STACK U UP PUMP STATION INTO PROTECTION STRUCTURE

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SLIDE 32

TESTING AT HO HORSØY

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SLIDE 33

TECHN HNOLOGY & & I INDUSTRY INITIATIVE VES ON S SUBSEA BOOSTING

4.0

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API 17N Industry Initiatives

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API RP 17N 17N

What is API RP 17N?

 Industry collaboration attempting to address a common approach

Technology Readiness Level (TRL) and associated Technology Risk Categorization (TRC) for development of new technology

 Focus on assessment of modification of existing

technologies/equipment to the project specific needs, not just new technologies

 Focus on assessment of new technologies already deployed,

particularly with respect to reliability

 Present assessment in the form of a risk/readiness matrix  References internal/external standards and codes

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SLIDE 35

TRC defin init itio ion wit ith Shell in interpretatio ion

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SLIDE 36

TRL D Defin init itio ion

21 April 2016

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SLIDE 37

API 17 17N Interpretatio ion: : Ris isk (TRC) / /Readin iness (TRL) Matrix ix

Technical Risk Categorization

Very High Technical Risk / Unacceptable Reliability

A

N/A

High Technical Risk / Low Reliability

B

N/A

Medium Technical Risk / Moderate Reliability

C

Low Technical Risk / Acceptable Reliability

D 25 2

1

7 6 5 4 3 2 1

Field Proven System Installed

(less than 3 years) or immature with respect to reliability

System Tested Environment Tested

New Technology,

  • r Some

Reconfiguration

  • f Existing

Technology

Prototype Tested

New Technology

  • r significant

reconfiguration

  • f existing

technology

Validated Concept Proven Concept Unproven Concept

Technology Readiness Level Note: Numbers above are examples. Not a reference to Draugen system.

21 April 2016

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INDUSTRY INITIATIVE VES

Longstep tie-back developments (>20 km)

  • Electrically heated lines
  • Long step out power supplies (<120 km)
  • Simplifying control system – onshore based system

Standardisation

  • API 17X Recommended Practice on Subsea Pumping Systems
  • Subsea Processing JIP – Standardization of Subsea Pumping.

Building market competitiveness

  • Pumping, higher pressures
  • Compression – Wet tolerance
  • Wet Compression – increasing the product range
  • Subsea water injection – Seabox (NOV)
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LONGSTEP O OUTS

  • Electrically heated lines:
  • Electrical heat tracing (Lowest power usage, highest CapEx)
  • Wet insulation direct electrical heating
  • Pipe in pipe direct electrical heating
  • Long step out power supplies
  • Onshore VSDs – 120 km & 12.5 MW vs.
  • Subsea VSD and switch gear (cable cost vs. subsea cost)
  • Simplifying control system – onshore based system
  • Communication protocols for safe shore based control of

subsea systems

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BUILDING MARKET COMPETITIVE VENESS Pumping

  • OneSubsea one major vendor, lack of competition
  • Qualifying FMC/Sulzer for the BC-10 project Brazil

Compression – Wet tolerance

  • Man and GE furthering technologies to be tolerant to 95% GVF

, 30% liquid w/w. Testing completed

  • Wet Compression One Subsea dual drive axis axial

compressor

  • WGC 4000 deployed for Statoil on Gulfaks
  • Developing WGC 6000, Testing. Chevon Gorgon project
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SLIDE 41

FIELD SCREENING OF SUBSEA B BOOSTING

5.0

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Technology Maturity, Field Screening Process

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Proven Technology – 2 2 Mil illio ion Runnin ing Ho Hours

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Single Phase Pump

50 100 150 200 250 10 20 30 40 50 60 70 80 90 100

GVF [%] Differential Pressure [bar]

Hybrid pump

300 350 400

WGC

725 1,450 2,175 2,900 3,625 4,350 5,075

Differential Pressure [psi]

Multi Phase Pump

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44

OneSubsea Desig ign Pressure Mil ilestones

1990 2000 2010 2005 1995 5,000 10,000 15,000 1997, Lufeng 2003, Ceiba 2006, Columba E 2015 2013, JSM 2014 1998, Troll

Design Pressure <psi>

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SLIDE 45

45

OneSubsea Motor Shaft Power Mil ile Stones

1990 2000 2010 2005 1995

200 400 600 800 1000 1200 1400 1600 1800 2000 2200 2400 2600 2800 3000

1997, Lufeng 1998, Troll 2007, Tordis 2013, JSM 2010, Gullfaks WGC 2009, Pazflor 2006, Columba E 1999, Topacio 2015

3400 3200 3600 3800

Q4-2013

Shaft power <kW>

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SLIDE 46

46

OneSubsea Water Depth Mil ilestones

1990 2000 2010 2005 1995 1000 m 500 m 0 m 1500 m 2000 m 2500 m 3000 m JSM Azurite Ceiba Topacio Troll Lufeng SMUBS 2015 Design depth <m> Julia

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SLIDE 47

Reservoir ir Development Concept

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Hig High l level Comparis ison of typic ical Subsea Fie ields EOR methods

Gas/Water/WAG Injection Boosting Gas Lift ESP Location Injection Well Wellhead Riser Base Downhole Riser Base Downhole Pros

  • Could reduce alternative

investments (Prod. Wells, Flow lines, risers and topside equipment)

  • High flexibility when

injecting into multiple reservoirs

  • Disposal produced water /

reduce topside cleaning requirements

  • Combine with artificial lifts
  • Very high volume

capability

  • Effective on long tiebacks,

requires smaller pipeline sizes

  • Positive effect on flow

assurance

  • Can be shared by multiple

wells/manifolds

  • High reliability and low

intervention costs

  • Excellent flexibility in

injection/production rate

  • Excellent gas handling
  • Excellent sand and solids

handling

  • No advanced subsea

rotating equipment is required.

  • High volume/rate

capability

  • Wide production rate

range between applications.

  • Effective on long

tiebacks

  • Positive effect on flow

assurance Cons

  • Large topside investments

Topside Water Injection System including pump with filter, de-aerator, piping, valves, etc.

  • Platform

modifications/extensions, installation, hook-up and commissioning work.

  • Weight and space

constraints

  • High pressure injection

pipelines

  • Extra Wells cost
  • High cost per unit
  • Not economical for very

small fields

  • Fewer applications

compared with Gas Lift/ESP

  • Limited GVF range
  • Compression cost is high

and compressor must be reliable

  • Gas delivery line can be

expensive

  • Fair operating efficiency,

but poor for intermittent gas lift.

  • Tend to cause or increase

flow assurance issues

  • Limited increase of

production rates

  • Less effective in deep water
  • Not effective on long tie-

backs

  • Narrow production

rate range for a specific application

  • Reliability is a major

issue

  • Poor solids handling
  • Poor gas handling

(without inlet gas separators).

  • High intervention

frequency and cost

  • Only a per well

application

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SLIDE 49

Pore to Process Evaluatio ion Involvin ing Artif ific icia ial L Lif ift

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Evaluatio ion of Subsea Boostin ing

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SCREENING OPPORTUNITIES

  • Project economics requires: CapEx, OpEx and Productio

ion profil iles

  • Generally Reservoir Engineers are given surface PQ curves

from which predict the impact of different surface options on reservoir production, from which to produce a profile from

  • This is a limited approach:
  • Poor accuracy
  • Limited functionality, insensitive to compositional changes
  • Requires fixed water cuts & GORs
  • Difficult to model constraints e.g. compressor curves etc.
  • Etc...
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PRODUCTION SYSTEM MODELLING

  • Integrated Production System Modelling
  • Shell uses PTEX’s Resolve software that links together and
  • ptimises:
  • GAP – surface network
  • Prosper - well
  • MoRes –subsurface

Coupled with:

  • Equipment Design
  • Availability modelling
  • Routing Logic
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OUTCOME

  • No endless iteration with Reservoir Engineering
  • Quality of information has been significantly approved, able

to assess between different options

  • Perform senstivity analysis: equipment sizing, uncertainities,

availability, routing, project timing etc.

  • System analysis, understanding what are the governing

constraints and what impact of changing them Production Profile Compressor Power Velocity Constraint

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SLIDE 54

Q & A

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SLIDE 55

Ha Have a Safe Day

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