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Statoil slug control
Gisle Otto Eikrem, Statoil RDIGuest lecture at NTNU -24/3- 2014
Outline
•Riser slugging•Slugging in gas-lift wells•Slug control•Slug control at Åsgard A
Riser sluggingRiser slugging – cyclic unstable flow. Liquid blockage at riser foot, pressure build-up, blow out,back-flow
Stabilized riser flow
Stabilized by feedback control from subsea pressure (Schmidt et.al. 1979)
Slugging•Uneven flow: liquid slugs and gas bobbles in multiphase pipelines•In slug control we simplify to two main types of slug flow:
–small slugs (< 5 min. periode): limited effect on receiving facilities–Often hydrodynamic or short terrain induced, water slugging
–severe slugs (10-180 min. periode): can result in shut down–Riser slugging, well slugging, transient slugging during start-up
Fixed choking, Riserslugging Active slug control, Even flowExamples from experiments at Sintef Lab at Tiller
Hydro dynamic slugsMade when waves hit the top of the pipe, liquid blocks gas flow, wave tops combine to slugs
Short slugs with high frequency (typ. 10-20 seconds)
Gas rate, liquid rate, pressure, gas volume, topandraphy decide degree of slugging
May trig riser slugging
Example from Tiller.
_., ,.Statoil
Stable Single Gas- Lift WellProductionchoke
Oil
Gas in
Gas liftchoke
Tubing
val
Reservoir
Multiphase Video IVideo of controlled multiphase
flowStable flow
Unstable Single Gas- Lift WellProduction choke
Oil
Gas in
Gas lift
Annulu :
Tubing
Reservoir
Multiphase Video IIVideo of severe slugging in gas lift well
Pro
duct
ion
Gas- Lift Wells350
Total Production for Unstable Well
300
250
200
150
100
50
00 2 4 6 8 10 12 14 16
Time (hour)
Effects of slug flow•Reduced production•Large variations in liquid rates into 1st stage separator
–Level variations: alarms, shut downs–Bad separation/water cleaning:
•WiO: carry- over, emulsions•OiW: hydro cyclones do no handle rate variations well
–Pressure pulses, vibrations and eqipment wear–Fiscal rate metering problems
•Variations in gas rate–Pressure variations – high pressure protection gives shut down–Liquid carry over into gas system–Flaring–Fiscal gas rate measuring problems
Stable Production Unstable
Pro
duct
ion
Gas- Lift Wells
80
Production from Gas-Lift Well
70
60
50
40
30
20
0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1Choke Opening (-)
Methods for for slug reduction and handling•Design changes for new projects
–Increase processing capacity, f.ex. separator size–Slug Catcher (expensive and space demanding)–Increase velocities by reduced pipe diameter: several pipes orreduced prod. by increased pressure drop–Gas lift in riser- foot or in well
100-1000 MNOK/pipe?
•Operational changes and procedures for existing fields–Topside choking: increase receival pressure, reduces prod.–Shut in wells
100 MNOK/year/pipe?
•Slug control, where active use of topside choke is used to–Reduce and avoid slug flow
0.5-2 MNOK/pipe?•Advanced control of receiving facilities to improve handling and reduce
consequenses of slugs
–Model based control (MPC) 1-3 MNOK/pipe?
Slug control•Objectives of slug control:
1. Improved regularity: stabile rater and redusert risiko for trip2. Reduced pipeline pressure: increased and prolonged tail
production and increased recovery•Available inputs:
– fast topside choke (f.ex. < 3 min closing time)•Measurements:
– subsea pressure transmitter (< 20 km away, time delay, etc)– pressure up- and downstream topside choke– multiphase meter, or densitometer and diff.press., for topside choke
•Solution: active control to stabilize pressure and rates and to smear out transient slugs during start- up/rate changes
_., ,.Stat
Oil out
Gas in
Injection valve
Reservoir
_., ,.Stat
Control StructurePressure Setpoint
u Onchoke ..... ...
Oil out
Gas in
Tubing
Injection valve
Reservoir
Shell Gas- Lift LaboratoryProduction
Tubes
Control Panel
Shell Gas-Lift Laboratory, Rijswijk, the Netherlands
Reservoir Valve and Gas Injection
Ope
ning
P
ress
ure
Experiment – DHP ControlDownhole Pressure
3
2.8
2.6
2.4
2.2
20 5 10 15 20 25 30 35
Time (min)Valve Opening
1
0.9
0.8
0.7
0.6
0.5
0 5 10 15 20 25 30 35Time (min)
Pro
duct
ion
Production
3.2
3
Production from Laboratory Gas Lift
Well Production wo/ ControlProduction w/ Control
2.8
2.6
2.4
2.2
2
1.850 60 70 80 90 100
Valve Opening (%)
Process modelling for control• Complicated and complex to model multiphase flow
– nonlinear, partioned system
• OLGA is the world leading transient multiphase flow simulator:
– must be tuned to reproduce field data
– some times not possible to reproduce results (ex. Tordis water slugging)
– used to investigate potential for slug flow
– not suitable for controller design (black box model, hidden equations)
– can be used to test controllers
• Simpler models have been developed to reproduce riser slugging:
– better suited for controller design
– not suited to predict flow regime
Model of Single Gas- Lift
Model of Single Gas- Lift
Model of Single Gas- Lift
Pre
ssur
e V
alve
Ope
ning
Simulation vs. LaboratoryOpening of Production Choke
1
0.8
0.6
0.4
0.2
00 2 4 6 8 10 12 14 16 18 20
Time (min)Downhole Pressure
3
2.5
2
1.5
1
Model Laboratory
0 5 10 15 20 25Time (min)
P
Statoil’s slug controller•Controls the pressure at the subsea manifold by the pipelineinlet•Helps liquid up by opening choke•Limits pressure increase after slug by choking•Pressure controller gives set point to rate controller•Controls flow into separator - ensures even flow•Automatic start-up and shut down of single wells
PB-SPPC
QP-SPFC
QPuP
FT
PSep T
Topside choke is used for control
Inlet
Subsea wells
Pi
QSub PTuSub
PW
Riser
PB
Topside choke
separator
•Removes severe slugging
Subseachoke
•Reduces smaller slugs
Laboppsett3" rør, 200m, 15 m riser Reguleringsventil på toppen av riserRiser og flere rørstrekk i PVC (gjennomsiktig)9 tetthetsmåler, 6 trykktransmittere Xoil, SF6.
Multiphase flow test facilities at Tiller• Lab set- up:
– 3” pipe, 200m length, 15m riser height– Control valve at riser top– Riser and parts of pipe in PVC– 9 densitometers, 6 pressure transmitters– Xoil and SF6– slug types: gravity dominated,
hydro dynamic, transient
Results from Tiller•Control of inlet pressure, volumetric rate and cascade control.•OLGA slug periode 50- 200 sec verified experimentally•Flow map and valve characteristics•Controller tuning•Control based only on topside measurements, i.e. without inlet
pressure•”Slow” ventiler: max closing time?
Experiment with inlet pressure controller
Slugging stopped effectively Step response in closed loop
Slug control in StatoilBarentshavet
Snøhvit
NorskehavetHeidrun Åsgard A
Norne
Norne HeidrunÅsgard
TyrihansKristin
Statfjord CNordsjøen
Statfjord
Snorre Gullfaks
Gullfaks C HuldraHuldra
Snorre B Huldra
Åsgard Q - 3 types of terrain slugging from well and riser
Possible slugging in low point in S-riser with typcalperiode 5 minutes and 1 bar variation in manifold pressure (neglectable)
P T
Åsgard A testseparator
Possible slugging in riser with typical periode 30 minutes and 5-10 bar
Q template 16 km long pipeline variation in manifold
pressure
P T
Well Q-2A
Possible slugging in well with typical periode 6-7 hours and 20-40 bar variation in down hole pressure
Pressure variations without slug control
Pressure downstream subsea choke varies from 85-98 barg
Topside choke 53%Downstream pressure varies from 220-260 barg
Temperature topside varies from 25-35 degrees
Åsgard A –slug control 06- 24.11.05Downstream pressure
Controller set point
Controlled pressure downstream subsea choke
Topside choke in manual
Control of pressure downstream subsea choke
Control of downstrea m pressure
Slug control downstream subsea choke
Pressure downstream subsea choke varies from 92-94 barg
Downstream pressure varies from 220-250 barg Topside choke 20-70%
Tuning slug control of downstream pressure
controller tuning periode Stability achieved
Fast variations from slugging in S- riser
Pressure upstream topside choke varies 70-77 barg with 5 min periode
Downstream pressure +-0.5 barg with 5 min periode
Topside choke 31-35% with 5 min periode
Oscillations restart when controller is turned off
DHP starts to oscillate
DHP stabilized at set point
controller turned off
controller in auto
New method to stabilize well Q- 2A
Pressure PCcontroller(PID)
P T
Åsgard A test separator
Qtemplate 16 km long pipeline
P T
Well Q-2A
Even better solution to handle well slugging: Downstream pressure stabilized by control with subsea chokeSet into operation 08.02.2006
Summary• Good results achived at several offshore installations from 2001 with simple PI-
controllers that control inlet (subsea) pressure and rate into receiving facilities with topside choke – simple and inexpensive solution
• Qualified technology after more than 5 years in operation• Achives even rates and reduced pipeline pressure and improves regularity and
makes it possible to increase and prolonge production, since it then is possible to operate closer to given constraints, f.ex. bubble point pressure, max sand free rate, hydrate temp., etc.
• Well: results indicate that it is possible to stabilize wells by control of the downstream pressure with topside or subsea choke and a PI controller
• Extended to handle other types of flow:– Gas dominated flow with surge waves– Start- up slugs
• Subsea production facilities
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