Statoil slug control

Gunleiv Skofteland and John-Morten Godhavn, Statoil R&D Process Control

Guest lecture NTNU 16/4-2007

Subsea

wells

Inlet

separator

Riser

Topside

choke

Subsea

choke

Pi

Pu

Q u

•Presentation of Statoil R&D Process Control Group

•Slugging

•Slug control

•Slug control in Statoil

•Field results from Åsgard Q (Åsgard A)

•Extended slug control for Urd (Norne)

Statoil er operatør for: 22 olje- og gassfelt

- 48% av Norges oljeproduksjon, 82% av Norges gassproduksjon

Process Control - we control what we promise

Control hierarchy for typical process plant

Basic control loops

(PID, FF,..)

Supervisory control/

model based control (e.g. MPC)

Stationary

optimization

(RTO)

Planning

PCDA

Supervisory

process control

computer

We work cross-discipline:

•On- and offshore, sea floor, wells,pipelines (multiphase), new/existingfacilities

•Modelling: black box, 1st principles,simple/advanced

•Simulation: D-SPICE, OTISS, Hysys,ASSET, OLGA, Matlab

•Optimisation: methanol plant, LNG-plant, oil platforms, production

•Control: simple tuning, design of newsolutions, advanced control

Statoil’s MPC-tool

- developed by us

Our goals:

-Improved quality

-Increased regularity

-Increased production

Slugging

Fixed choking

Riser sluggingActive slug control

Even flow Examples from experiments at Sintef Lab at Tiller

•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, etc

Riser sluggingRiser slugging – cyclic unstableflow. Liquid blockage at riserfoot, pressure build-up, blowout, back-flow

Stabiliced by feedbackcontrol from subsea pressure(Schmidt et.al. 1979)

Hydro dynamic slugs

!Made 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.

Effects of slug flow

•Large variations in liquid rates into 1st 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

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 or

reduced prod. by increased pressure drop– Gas lift in riser-foot or in well

•Operational changes and procedures for existing fields– Topside choking: increase receival pressure, reduces prod.– Shut in wells

•Slug control, where active use of topside choke is used to– Reduce and avoid slug flow

•Advanced control of receiving facilities to improve handling andreduce consequenses of slugs

– Model based control (MPC)

0.5-2 MNOK/pipe?

1-3 MNOK/pipe?

100-1000 MNOK/pipe?

100 MNOK/year/pipe?

Process description for control• Multiphase flow in long pipelines with varying inclination

• Here: slug flow in pipes from satellite fields a few km from oil rig with riser

– similar process: well slugging in platform- and subsea wells

• Modelling:

– 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

Slug control• Slugging challenge for receiving facilities: oscillations in rate, pressure and

separator levels• 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)• Choking has limited effect on hydrodynamic a.o. smaller slugs• 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

• Conventional solution for slug reduction: fixed choking– increases pipeline pressure and friction loss: reduced production

• Better solution: active control to stabilize pressure and rates and to smearout transient slugs during start-up/rate changes

Statoil’s slug controller

•Removes severe slugging

•Reduces smaller slugs

•Controls the pressure at the subsea manifold by the pipeline inlet

•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

Subsea

wells

Inlet

separator

FT

FC

QP-SP

uP

Riser

Topside

choke

PT

PC

PB-SP

PB

Subsea

choke

QP

Pi

PW

uSub

PTPSep

QSub

Topside choke is

used for control

Statfjord

Huldra

Snøhvit

Kristin

Barentshavet

Norskehavet

Nordsjøen

Tyrihans

Slug control in Statoil

ÅsgardHeidrun

Norne

Gullfaks

Heidrun Åsgard A Norne

HuldraGullfaks CStatfjord C Snorre B

Huldra

Snorre

Slug control in Statoil• Research and experiments:

– Large scale experiments at Tiller 1988-89– 4 weeks with experiments at Tiller 2001– 7 weeks with experiments på Tiller 2002 (samarbeid with Hydro)– 1 paper with Heidrun results at Multiphase’03– 1 paper with Tyrihans sim. results at Multiphase’05– 1 paper with Tordis results på IFAC WC’05– 1 paper with Åsgard Q results at Multiphase’07– 2 journal papers with experimental results from Tiller (SPE J.+JPC)– 1 journal paper with field results from Åsgard Q subm. to SPE J– 2 PhD students (Hardy Siahaan, cyb. & Heidi Sivertsen, chem.)

• Field installations:– Heidrun Northern Flank D- and E-line from 2001– Statfjord Northern Flank (ABB’s AFC) 2002– Two-phase pipe from Gullfaks B to Gullfaks C 2003– Two 11 km pipes from Tordis to Gullfaks C 2003– Huldra-Heimdal rich gas pipe liquid rate control 2004– Q-Åsgard A 2005– Urd (Svale and Stær) to Norne 2005– Snorre B subsea well 2006

Multiphase flow test facilities at Tiller

Laboppsett

3" rør, 200m, 15 m riser

Reguleringsventil på toppen av riser

Riser og flere rørstrekk i PVC (gjennomsiktig)

9 tetthetsmåler, 6 trykktransmittere

Xoil, SF6.

sluggtyper (tyngdedominert, hydrodynamisk, transient)

• 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 cascadecontrol.

•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?

Ekperiment with inlet pressure controller

Slugging stopped effectively Step response in closed loop

Åsgard Q - 3 types of terrain slugging from well and riser

Åsgard A testseparator

PT

PT

Q template

Well Q-2A

16 km long pipeline

Possible slugging in wellwith typical periode 6-7hours and 20-40 barvariation in down holepressure

Possible slugging in riserwith typical periode 30minutes and 5-10 barvariation in manifoldpressure

Possible slugging in lowpoint in S-riser with typcalperiode 5 minutes and 1bar variation in manifoldpressure (neglectable)

Pressure variations without slug control

Downstream pressurevaries from 220-260barg

Temperature topsidevaries from 25-35 degrees

Topside choke 53%

Pressure downstreamsubsea choke variesfrom 85-98 barg

Åsgard A –slug control 06-24.11.05

Control of pressuredownstream subsea chokeTopside choke in manual

Control ofdownstreampressure

Downstream pressure

Controllerset point

Controlled pressuredownstream subsea choke

Slug control downstream subsea choke

Pressure downstreamsubsea choke variesfrom 92-94 barg

Topside choke 20-70%

Downstream pressurevaries from 220-250barg

Tuning slug control of downstream pressure

controller tuning periode Stability achieved

Fast variations from slugging in S-riser

Topside choke 31-35%with 5 min periode

Pressure upstream topside chokevaries 70-77 barg with 5 min periode

Downstream pressure +-0.5barg with 5 min periode

Oscillations restart when controller is turned off

controller turned off

DHP starts to oscillate

controller in auto

DHP stabilized at set point

Åsgard A testseparator

PC

PT

PT

Qtemplate

Well Q-2A

16 km long pipeline

Even better solution to handle well slugging:Downstream pressure stabilized by control with subseachoke

Set into operation 08.02.2006

Pressurecontroller(PID)

New method to stabilize well Q-2A

Project subsea production facilities (Tordis)

• Integrated simuleringer (OLGA-ASSETT) of pipe with multiphase split, pumps (water

and multiphase), choke and separator

SSS water

level control

SSS

pressure

control

New slug

control loop

Well 1

Tordis A

inlet

separator

Riser

11 km flowline

Well 2

Well N

Tordis

subsea

separator

Water

reinjection

11 km flowline

Tordis B

inlet

separator

RiserMultiphase

booster

pumps

Water

booster

pumps

Split range

modulePIC

FIC

FIC

PIC

LIC

SEPTIC

MPC

LIC

LIC

LIC

LIC

Tordis.exeTordis.exe

Multiphase split – uneven flow in 2 equal pipes

• controller activated after 6 hours and balances flow to 50% in each pipe

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