The HSP – A Versatile Artificial Lift Choice for Kraken

The HSP – A Versatile Artificial
Lift Choice for Kraken
SPE EuALF
June 2014
Adam Downie (EnQuest),
Abhishek Bhatia (Clyde Union Pumps, SPX)
Outline
Kraken overview
Artificial lift challenges
Artificial lift selection
Viscosity corrections
Pump design optimisation
Completion design
Production infrastructure
Summary
1
Introduction
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)
2
Reservoir & PVT
Rock Quality
KRAKEN NORTH AREA
Pb = 1300 psia
GOR = 127 scf/stb
API gravity – 13.9°
Oil viscosity – 125cP
High porosity (>30%)
High permeability (3-8 Darcies)
9/02b-6
Unconsolidated
Formation
CENTRAL AREA
Heimdal-III sands (Palaeocene)
Pb = 1447 psia
GOR = 147 scf/stb
API gravity – 15.1°
Oil viscosity – 78cP
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)
SOUTH AREA
Pb = 882 psia
GOR = 85 scf/stb
API gravity – 13.7°
Oil viscosity – 161cP
Shallow reservoir (3900 ft TVD-SS)
Cool (108°F)
Fluids – 3 PVT regions
3
Key Artificial Lift Considerations
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 high
watercut
Preference for FPSO-based subsea development due to multiple
drill centres required (4)
4
Typical Trends in Pressure, PI, Watercut
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
5
Effect of Temperature on Oil Viscosity
TRES : 42ºC
Tseabed : 5ºC
Conclusion: need to retain heat in the
system.
6
HSP - Principle of Operation
Original Image © Clyde Union Ltd
7
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
8
Comparison of Artificial Lift Options
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
Key HSP Design Features
Self-Regulating Turbine
Thrust Balance
- Hydrostatic ceramic drum
utilises clean feed from
turbine
Elimination of Mechanical Seal /
Protector
- Simple throttle bush isolates
between turbine and pump
Ultimate Wear & Corrosion
Resistance for Maximum Life
- Super Duplex, Nickel & Cobalt
Alloys and Ceramic Bearings
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
Self-Regulating Pump
Thrust Balance
- Hydrostatic ceramic drum
utilises clean feed from
turbine
Ultra long Life Hydrostatic
Ceramic Bearings
- Non-contacting for low wear
utilising clean turbine feed
Class leading Performance to 75%
Free Gas Level Continuously
- Patented multiphase pump stage
design
Original Image © Clyde Union Ltd
Power Delivery via Simple
Industry Standard Tubular
Thread Connections
10
Circulation & Pre-heating Functionality
Power Fluid
Hydrocarbon
AAV
XOV
PWCV
AWV
PCV
AMV
PMV
Turbine
NRV
Pump Leaky
NRV
SSSV
FLCV
Original Image © Clyde Union Ltd
HSP
PWV
•
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 preheat all exposed subsea metalwork
and mitigate any viscosity related
issues.
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
Used to generate corrections for Head,
Capacity as a function of:
Viscosity
% Best Efficiency Flowrate
rpm
Original Image © Clyde Union Ltd
Used to validate predictions of
temperature rise based on efficiency
13
Impact of P/T Variation on Viscosity and Head Correction
50.00
140.0
100.0
46.00
80.0
Pressure
Temperature
60.0
44.00
40.0
42.00
20.0
1
2
3
4
5
6
7
8
9
10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Correction Factor
0.0
1.0
Stage Temp (deg C)
48.00
40.00
500.0
400.0
Head, Capacity
Correction
300.0
Oil Viscosity
200.0
Viscosity (cP)
Stage Pressure (bar)
120.0
100.0
0.8
0.0
1
2
3
4
5
6
7
8
9
10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Stage Number
Original Image © Clyde Union Ltd
14
Pump/Turbine Sizing
Selected a pump/turbine combination to maximise production within
constraints:
Power Water Supply
Power Water Pressure
Power Water Rate (per well)
320 barg
15,000 bwpd
Reservoir / Completion
Min FBHP
Max Liquid rate
Pb-200psi
20,000 blpd
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
15
Range of HSP Operation
Illustrates flexibility of HSP over life-of-field conditions from:
•
•
Early, dry oil / low PI
Late, high watercut / high PI
16
Completion Design
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
17
Modelling Flow in Annulus around Clamps
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
18
Completion Schematic
POWER
WATER
CHOKE
PRODUCTION
CHOKE
AAV
AMV
PMV
TVDRKB
480'
700’
C.36” x 30"
C.20"
1600’
Venturi flowmeter/ PDP gauge
7" Tubing
Speed Probe
20,000 bpd HSP
3600’
4000’
Scale
Inhibitor
Injection
C.13 3/8"
C.10.3/4 x 9.5/8"
Pump
inlet
pressure
sensor
51/2" SCSSV
Inlet
Protector
Screen
7" Tailpipe
5" Premium Screens, OHGP
Wells
FPSO Design Capacities
Design
Capacities
Peak Liquids
Production:
460 mbd
Peak
Liquids:
460
mbd
Oil Production
80 mbd
Oil
Prod
80275mbd
Water
Production
mbd
Gas Production
MMscf/d
Gas
Prod
2020MMscf/d
Water Injection
275 mbd
Water
Prod
275
mbd
Power Water
225 mbd
Water
Injection 275
mbd
Power Water
225 mbd
20
Summary
▪ 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
21
Acknowledgements
▪
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.
22