The HSP – A Versatile Artificial Lift Choice for Kraken

Adam Downie (EnQuest),

Abhishek Bhatia (Clyde Union Pumps, SPX)

SPE EuALF

June 2014

Outline

1

� Kraken overview

� Artificial lift challenges

� Artificial lift selection

� Viscosity corrections

� Pump design optimisation

� Completion design

� Production infrastructure

� Summary

Introduction

2

Located in Block 9/2b

� Discovered 1985

� 400 km NE of Aberdeen

� 380 ft water depth

� Licensees: EnQuest, Cairn Energy,

First Oil

Adjacent Heavy Oil Developments

� Bentley (Xcite)

� Bressay (Statoil)

� Mariner (Statoil)

Closest Field Analogue

� Mariner (Heimdal-III)

Reservoir & PVT

3

SOUTH AREA

Pb = 882 psiaGOR = 85 scf/stbAPI gravity – 13.7°Oil viscosity – 161cP

CENTRAL AREA

Pb = 1447 psiaGOR = 147 scf/stbAPI gravity – 15.1°Oil viscosity – 78cP

KRAKEN NORTH AREA

Pb = 1300 psiaGOR = 127 scf/stbAPI gravity – 13.9°Oil viscosity – 125cP 9/02b-6

Rock Quality

� High porosity (>30%)

� High permeability (3-8 Darcies)

� Unconsolidated

Formation

� Heimdal-III sands (Palaeocene)

� 11 km x 1.5 km

� Relatively thin sands (30-120’, average 50’)

� High Kv / Kh

� No underlying aquifer (underlain by shale)

� High N:G (75-98%, average 90%)

� Low reservoir pressure (1742 psia)

� Shallow reservoir (3900 ft TVD-SS)

� Cool (108°F)

Fluids – 3 PVT regions

Key Artificial Lift Considerations

4

� Normally pressured, shallow reservoir – 3900 ft TVDSS

� Relatively high viscosity – 78 to 161 cP at reservoir conditions

� Low GORs – 85 to 147 scf/stb

� High drawdowns and offtake rates required for economics

� 5:1 increase in PI from initial dry oil conditions to late-life highwatercut

� Preference for FPSO-based subsea development due to multipledrill centres required (4)

Typical Trends in Pressure, PI, Watercut

5

� High initial drawdowns

� Initially stable PI at 0% watercut,

BHP constrained

� Rapid rise in PI as watercut

develops

� Well becomes rate constrained at

high watercut

� Drawdown diminishing with time

6

Effect of Temperature on Oil Viscosity

TRES : 42ºC

Tseabed : 5ºC

Conclusion: need to retain heat in the system.

HSP - Principle of Operation

7Original Image © Clyde Union Ltd

8

Comparison of Artificial Lift Options

Gas Lift ESP Jet Pump HSP

FPSO Compatibility

Achieves required

drawdowns / rates?

Viscosity Management & Operability

Expected reliability & robustness

Topsides Fluid Handling Burden

Subsea Complexity

Completion Complexity

Single design for Life of Field?

HSP: � Addresses flow assurance concerns

� Satisfies life-of-field performance requirements

� Excellent and well documented track record in analogue application

� SELECTED FOR DEVELOPMENT

� Gas Lift• Not a contender – high lift rates required – little solution gas available.

� ESPs – feasible option but:

• Sizing studies showed a single ESP design could not be used for life of field

• Diluent injection below the pump or at the wellhead may be needed (or heating system) for startup

• Very high number of power cables to accommodate in a FPSO swivel system

� HSPs & Jet Pumps

• Overcome some of the key flow assurance issues presented by the high crude viscosity

• Heated power fluid can be used to reduce fluid viscosity (and also pre-heat pipelines)

• Both have similar efficiency, but at lower PI HSPs more efficient.

• Track record of HSPs in subsea applications now much greater than jet pumps – over 45 HSPs

installed in Captain

• Downside – more fluids to handle topsides + additional pumps to provide power fluid.

Final selection in favour of HSPs, based on:

• Ability to deliver the required drawdowns and liquid rates

• “In-built” management of high crude oil and emulsion viscosities

• Expected high reliability – essential in subsea to minimise field OPEX

9

Comparison of Artificial Lift Options

Key HSP Design Features

10

Ultimate Wear & Corrosion

Resistance for Maximum Life

- Super Duplex, Nickel & Cobalt

Alloys and Ceramic Bearings

Self-Regulating Turbine

Thrust Balance

- Hydrostatic ceramic drum

utilises clean feed from

turbineElimination of Mechanical Seal /

Protector

- Simple throttle bush isolates

between turbine and pump

Class leading Performance to 75%

Free Gas Level Continuously

- Patented multiphase pump stage

design Power Delivery via Simple

Industry Standard Tubular

Thread Connections

Robust Drive with Unrivalled

Operating Window

- Compact, high speed,

multistage water driven turbine

Low Inertia, High Precision

One Piece Shaft

- Shop assembled integrated

unit with no couplings

Ultra long Life Hydrostatic

Ceramic Bearings

- Non-contacting for low wear

utilising clean turbine feed

Self-Regulating Pump

Thrust Balance

- Hydrostatic ceramic drum

utilises clean feed from

turbine

Original Image © Clyde Union Ltd

Circulation & Pre-heating Functionality

AMV

AAV

AWV

PWCV

PMV PWV

PCV

XOV

SSSV

FLCV

Hydrocarbon

HSP

Power Fluid

Turbine

NRV

Pump Leaky

NRV

• Flushing – Following the shutdown,

flow lines can be flushed with water

to displace the hydrocarbons.

• Pre-heating – Hot water can be

circulated in the flow lines to pre-

heat all exposed subsea metalwork

and mitigate any viscosity related

issues.

Original Image © Clyde Union Ltd

Effect of Viscosity on Pump Design

� Oil viscosity higher than in earlier HSP applications

� Important to predict impact of high viscosity on:

• Pump sizing – no. of pump/turbine stages

• Power water pressure and rate requirements (facility design)

� Industry corrections unsuitable for axial flow pumps

� Conclusion: needed to perform flow loop tests to:

• obtain corrections to head, capacity and power for viscosity & speed effects

• assess fluid temperature rise across each stage & pump performance

• refine stage-by-stage models of pump hydraulic performance

• refine HSP modelling within proprietary nodal analysis

12

Flow Loop Testing – Sample Output

13

Used to generate corrections for Head,

Capacity as a function of:

� Viscosity� % Best Efficiency Flowrate

� rpm

Used to validate predictions of

temperature rise based on efficiency

Original Image © Clyde Union Ltd

14

40.00

42.00

44.00

46.00

48.00

50.00

0.0

20.0

40.0

60.0

80.0

100.0

120.0

140.0

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

Sta

ge T

em

p (

deg

C)

Sta

ge P

ressu

re (b

ar)

Pressure

Temperature

0.0

100.0

200.0

300.0

400.0

500.0

0.8

1.0

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

Vis

co

sit

y (

cP

)

Co

rre

cti

on

Fa

cto

r

Stage Number

Head, CapacityCorrection

Oil Viscosity

Impact of P/T Variation on Viscosity and Head Correction

Original Image © Clyde Union Ltd

Pump/Turbine Sizing

15

� Selected a pump/turbine combination to maximise production within

constraints:

� Represents significantly higher head and power requirements than for

Captain HSPs)

• Final pump design > 24 x TP145AH stages (7 more)

• Final turbine design > 18 x T60C – (7 fewer)

� Larger OD T60C turbine blade allows higher HHP to be generated with slight

increase in PW supply pressure – more power fluid

Power Water Pressure Power Water Rate (per well)

320 barg 15,000 bwpd

Min FBHP Max Liquid rate

Pb-200psi 20,000 blpd

Power Water Supply

Reservoir / Completion

Range of HSP Operation

16

Illustrates flexibility of HSP over life-of-field conditions from:• Early, dry oil / low PI

• Late, high watercut / high PI

Completion Design

17

� No requirement for free flow facility – no free gas cap, normally pressured

� Significant well cost saving if 10 ¾” casing could be used instead of 11¾”

� Needed to confirm frictional pressure loss in annulus across clamps acceptable

Conclusion > frictional pressures loss small, but not insignificant ~ 50 psi

Modelling Flow in Annulus around Clamps

18

� Concern that higher velocities could induce vortex shedding around

clamps:• Depending on frequency, could cause excitation of control lines,

inducing stress and mechanical damage

• CFD analysis carried out to investigate flow behaviour

Conclusion > at the predicted frequency for vortex shedding, fatigue life

of control lines effectively infinite – no issues

C.36” x 30"

7" Tubing

C.10.3/4 x 9.5/8"

C.20"

700’

1600’

4000’

TVDRKB

51/2" SCSSV

5" Premium Screens, OHGP

Venturi flowmeter/ PDP gauge

20,000 bpd HSP

480'

AMV

AAV

PMV

7" Tailpipe

Pump

inlet

pressure

sensor

Speed Probe

PRODUCTION

CHOKE

POWER

WATER

CHOKE

C.13 3/8"3600’

Completion Schematic

Inlet

Protector

Screen

Scale

Inhibitor

Injection

Wells

20

Design Capacities

Peak Liquids: 460 mbdOil Prod 80 mbd

Gas Prod 20 MMscf/dWater Prod 275 mbd

Water Injection 275 mbdPower Water 225 mbd

FPSO Design Capacities

Peak Liquids Production: 460 mbd

Oil Production 80 mbd

Water Production 275 mbd

Gas Production 20 MMscf/d

Water Injection 275 mbd

Power Water 225 mbd

Summary

21

▪ HSP selected as the optimal solution for Kraken based on

performance, operability and expected reliability

▪ Mitigates many of the flow assurance issues which high viscosity

fluids would otherwise present in a subsea context

▪ Kraken HSP a significant uprating of existing design - addresses

higher head and power requirements

▪ Completion design builds on the lessons learned on Captain, and

simplifies where appropriate

▪ Subsea and topsides infrastructure has been designed around

the requirements of the HSP

Acknowledgements

22

▪ Bill Harden, Scott McAllister, Ron Graham at Clyde Union Pumps (an SPX brand) for their expertise and support throughout the project.

▪ Colleagues within the well engineering and subsurface departments of the Kraken

team

▪ Our field Partners Cairn Energy and First Oil, and EnQuest’s management for their

kind permission to present this information.