Subsea processing - · PDF fileWhy subsea processing in Statoil? ... Principle Engineer, subsea processing [email protected] Thank you. Title:

1 - Classification: Internal 2011-05-24

Subsea processing

IFEA seminar: Subsea Kraftforsyning

Stavanger, 25 mai 2011


Subsea Processing

• Introduction to Subsea Processing

− Why, where, what is subsea

processing

− Key drivers

• Key technologies

− How they work

− Relevant experience in Statoil

• Subsea processing future needs and

requirement for subsea HV power


Subsea in Statoil

• Today more than 50% of

Statoil production is from

subsea production systems

• Statoil has approximately

480 subsea wells

• Number of wells increasing

with new tie-in projects to

existing facilities

• Subsea processing used to

increase recovery

Tyrihans

Tordis

Troll Pilot

Åsgard

Gullfaks

Ormen Lange

Lufeng


What is subsea processing?

Manipulating the well stream between wellhead and

host.

By:− Hydrocarbon boosting

− Separation systems

− Gas compression

− (Raw seawater injection)

Prerequisites and enablers:− Long distance / high voltage power

− Advanced process monitoring and control

− Cost-efficient installation, maintenance and retrieval

Technology

Asset

Infrastructure

Pipelines

InfrastructureInfrastructure

Pipelines


Why subsea processing in Statoil?

• Benefits:

− Increased hydrocarbon recovery

− Accelerated production

− Reduced CAPEX / OPEX

− HSE

• These benefits typically become more significant in fields with:

− Deeper water

− Longer step-out / distance

− Lack of infrastructure

− Harsher environments

• Enabling technology (e.g. ultra-deepwater, ”tight, deep reservoirs” and difficult fluids)

480 subsea wellsmore than 50% of Statoil’s total production.


Effects of subsea boosting

P

Pump or

compressor


Effect of subsea boosting:

• Accelerated Production

• Increased Total Recovery

• Shorter Recovery Time

Time

Pro

du

cti

on

Normal Production

Profile

Boosted Production

Profile

time


Pfwh Inflow

Performance

Relation

(IPR)

System

Resistance

Curve

Q1

Natural

Flow

Q2

MPP

Discharge

pressure

Curve

Boosted

Flow

dQ

(Flow

Increase)

Subsea Processing Principle (Boosting)

dPrequired

MPP must be able to

Pump Q2 with dP

Q


Effects of subsea separation

P


Less dP required with separation, for a given inflow & pipeline ID

dP Requirement

Boosting

Without

water

With

water

System

Resistance

Curve

without

water

System

Resistance

Curve

with water

Natural

Flow

With

water

Natural

Flow

Without

water

dQinflow - Boosting

Qinflow

Inflow

Performance

Relation (IPR)

With water

Pfwh

Subsea Processing Principle (Separation & Boosting)

Removal

of water

(separation)


Relevant experience in Statoil


Statoil subsea processing historystepwise development

1996

Gullfaks

First multiphase

Pumps (topsides, part

of Framo

commercialisation)

2003

Norne

Technology

program

Subsea

separation

concept

developments

1986

Start Poseidon

multiphase pump

development

1997

Lufeng

Subsea

pumps

2000

Troll

Subsea water

removal and

injection

2007

Tordis

Subsea water

removal &

injection, oil &

gas boosting

2009

Tyrihans

Subsea raw

seawater

injection (ready

for operation)

2005

Troll Pipe

separator

Qualifications

Subsea water

removal

Lufeng Operation 1997 - 2009

Tordis 2007

Tyrihans

SRSWI

Troll Pilot 10 years -

2009

Pipe separator


Statoil experience with subsea pumps

PoseidonIFP,Total, Statoil

LufengGullfaks A

topside

Troll Pilot

TordisTyrihans

19861994

19971999

20072009

0,4 MW 0,4 MW 1,6 MW 2,3 MW 2,7 MW


Subsea pumps – applications today:

Well stream boosting

− Multiphase boosting

• Helico axial

• Twin screw

− Centrifugal/Hybrid/ESP (limited GVF)

Subsea separation and boosting

− Centrifugal

− Hybridcombination of MP and centrifugal

− ESP

Water injection

− Centrifugal


Lufeng field development

• Distance to host: 1 km

• Water Depth: 330 m

• Pumps: 5x0.4MW (SPP)

• Flow: 20 000 m3/d

• Drive system: 5x VSD

• Subsea power: Direct drive

• Prod. start-up : 1997

• Prod. Shut-down: 2009

Subsea pumps:

- Enabeled field development

- Extended field life from 5 to 12 years


Statoils experience with subsea separation

Troll Pilot

1999 Tordis

2007

Norne Technology

Program

2003-5

Pazflor

Totaloperator

2011

Troll pipe separator

qualifications

2005


Troll Pilot field development



• Pump: 1.8MW (SPP)

• Flow: 63,000BBLD (25,000BBLD oil)

• Drive system: VSD



Installed 1999

Started 2000

Still stable and profitable operation after

10 years on the seabed

Currently injecting 20 000 bbl/d ->

increasing oil capacity at Troll C


Troll Pilot

Operational experience2000: Electrical earth fault in wet mate

connector during first start-up –Fixed in 2001

2003: Pump required intervention

2003: Inductive level instrument lost function, due to an

electrical jumper

2005/06 The inductive level detector jumper replaced

2007: Pump upgrade

From 2008 100% availability


Tordis SSBI field development

SSBI station

WI Well

PLIM

Existing Tordis subsea



• Pumps: 2x2.3MW (SPP+MPP)

• Flow: 189,000BBLD (57,000BBLD oil)

• Drive system: 2x VSD



Ambition: Increase oil recovery from 49% to 55% (~36.5 Million bbl)


Tordis

Operational Experience

Tordis without SSBI:

− Oil: 25000 bpd

− Total Liquid: 130000 bpd

− Water cut: 80 %

Tordis including SSBI:

− Oil: 40000 bpd

− Total liquid 180000 bpd

− Water cut: 80 %

− Water inj: 65000 bpd

100% availability of subsea processing station

Sand handling system working properly

Oil content way below specified 1000 ppm


Statoils experience with subsea water injection

Tyrihans

RSWIinstalled

2009

2011

SWIT

Phase 1

(Statoil not part of JIP)

2010

SWIT

Phase 2


22

W (SRSWI)

•Distance to host: 40 km

•Water Depth: 270 m

•Pumps: 2x2.5MW SPP

•Flow: 88,000BBLD

•Drive system: 2 x topside VSD’s

•Subsea power: 2 x subsea

transformers

•Prod. start-up : 2011

Tyrihans SRSWI field development

Experience transfere:

•Integrated control system

•Pumps 100 % available since installation

•Awaiting injection well


Subsea Compression

Gullfaks SCS

Åsgard Subsea Compression

Ormen Lange SCS Pilot

Snøhvit future development

2014?

- Topside experience, KBS etc

- Compact compressor

- Compact gas scrubbers

- Power system

- All electric control systems

- Material testing


Ongoing subsea compression projects

Field Gullfaks Åsgard Ormen Lange *

Planned Installed 2014 / 15 2014 2016

Design life (yrs) 20 30 30

Depth (m) 135 260 850

Tieback (km) 15 40 - 50 120

No of units 2 2 4

Pressure boost (bar) 30 50 60-70

Power (MW) 10 20 58

VSD Topside Topside Subsea

* Operated by Shell


Subsea Compression…. Not only a submerged compressor

Picture from Ormen Lange Pilot

Subsea process equipment Subsea power equipment



Future needs

Subsea power distribution and subsea VSDs,

Larger dP pumpsLonger step outs

Deeper waters

Colder

Future needs

Environments

Heavier fluids

Larger hydrostatic pressures

Deeper reservoirs

500 km step-outs 3000 m water depth 100 MW power


Longer step outs

New areas - e.g. Barents sea

− limited infrastructure

− larger step out distances from hostToday: Tyrihans ca 43 km – > 200 km

− Limited volumes in place

long tie backs if

• separation to transport quality

• cost allows

Impact for Subsea power:

− High dP pumps to overcome

long distance transportation

− Subsea coalesher

− Local subsea water injection

Larger motors to reduce

number of pump units

Subsea power

distribution

Larger motors, subsea VSD and HV power

distribution, Local power?,


Deeper: GoM drivers

P

• Statoil leases in deep water (1500-3000 m)

• Large volumes in place;

low initial recovery factor

• Paleogene reservoirs:

− Relatively low GOR

− Relatively low bubble point

− Low permeability

low(er) operating pressure

− Deep reservoirs; 7000 m below seabed

High shut-in pressure; casing, penetrators

• Seabed pumps from first oil

• (Single phase followed by High dP MPP/hybrid pumps)

• Subsea ESPs and subsea HV power distribution

SPPMPP

ESP

Needs:

• Increased reliability/regularity

• Reduced intervention costs

• Subsea “HIPPS”


Colder

• Arctic areas

− Long distance power supply

− Subsea HV power distribution

− Lager pumps/motors to reduce number of

units

− Separation to transport quality

• Heavier fluids

− Lager motors

− In-field flowline heating

− Subsea HV power distribution

− Subsea coalesher

− SLPS


Ambitions for subsea processing

and subsequent subsea HV power

Ambitions

• Efficient transport of conditioned well streams over long

distances

− in long term up to 500 km utilizing separation, liquid

boosting and wet gas compression.

• Develop abilities to access resources in deep water and

harsh environments.

− Also heavy oil prospects

• Ensure that subsea gas compression is an integral part of

future developments in accessing the international gas

value chain

• Maintain production rates in the Norwegian Continental

Shelf through deployment of subsea processing as a major

part of Statoil’s increased hydrocarbon recovery initiative.

Needs for subsea HV power

• Efficient subsea power transmission systems

• Reliable/ high endurance rotating machinery and subsea HV power equipment

• Advanced processing systems will require additional utility systems -> power and power distribution

• Cost effective solutions (not only key equipment, but pipes, power lines, umbilicals and distribution systems etc)

• Subsea HV power distribution and control

• Lager units; e.g up to 5-6 MW pumps, 15 MW compressors

• Smaller units – within existing technology

• Smaller compressor units; 3-6 MW

• Subsea distribution and power control (host platform is weight and space limited)

We seek your ideas to meet our ambitions…


Subsea processing – at IFEA Subsea power conference 2011

Birgitte Nordheim Tveter

Principle Engineer, subsea processing

[email protected]

www.statoil.com

Thank you

Documents

Subsea processing - · PDF fileWhy subsea processing in Statoil? ... Principle Engineer, subsea processing [email protected] Thank you. Title: