the hsp – a versatile artificial lift choice for kraken · the hsp – a versatile artificial...
TRANSCRIPT
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.