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