Active Slug Management

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Copyright 2006, Society of Petroleum Engineers

This paper was prepared for presentation at the 2006 SPE Annual Technical Conference andExhibition held in San Antonio, Texas, U.S.A., 24–27 September 2006.

This paper was selected for presentation by an SPE Program Committee following review ofinformation contained in an abstract submitted by the author(s). Contents of the paper, aspresented, have not been reviewed by the Society of Petroleum Engineers and are subject tocorrection by the author(s). The material, as presented, does not necessarily reflect anyposition of the Society of Petroleum Engineers, its officers, or members. Papers presented atSPE meetings are subject to publication review by Editorial Committees of the Society ofPetroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paperfor commercial purposes without the written consent of the Society of Petroleum Engineers isprohibited. Permission to reproduce in print is restricted to an abstract of not more than300 words; illustrations may not be copied. The abstract must contain conspicuousacknowledgment of where and by whom the paper was presented. Write Librarian, SPE, P.O.Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435.

AbstractSlug flow, or instabilities, in multiphase wells and -pipelinesfeeding oil- and gas processing facilities may causeoperational challenges related to avoiding unplanned partial-or complete shutdowns, satisfying flaring volumes, managingsand production, maintaining on-spec production, proving offiscal meters, etc. Conventional approaches to manage slug

flow in wells and pipelines include: choking the well/pipeline,increasing gas lift rate(s), and/or providing overcapacity to

accommodate the slugs that are produced erratically. All theseconventional approaches imply inefficient production orexpensive over-design. In this paper, a different—fromchoking and use of gas lift for stabilization—non-intrusiveapproach to slug management in wells and pipelines is presented. However, it will typically be complementary toother means, like choking and excessive use of gas lift, ofhandling slug flow challenges. The approach also applies to

handling challenges related to oscillations and transients in thetotal production system, not only in the wells and pipelines. Itmay be interpreted as slug management from a practicaldynamical systems point-of-view. It has emerged as a result of providing oil- and gas field operators with services andsolutions with respect to slug management since the late1990’s. The associated base of experience includes hands-on

experience from approximately 20 fields—mainly in the NorthSea. The approach consists of solutions for automatic control,or, active feedback control, of well(s)/pipeline(s) andassociated separators as well as services for generic handlingof oscillations/instabilities including control strategy selectionand -tuning. Field results from application of the approach areincluded. The experience gathered during these years supportsthat an integrated view of the dynamics of well(s)/pipeline(s)

and the processing facilities is required in order to sort out proper activities and means for improving the slugmanagement. Furthermore, it is important that this view is

based on an analysis of relevant historical data. The analysis phase should involve key personnel from operations like

senior operators, production-, and process engineers. It is ourexperience that operators who, as part of their slug

management strategy, include an approach with characteristicssimilar to the ones summarized above, will improve operationssignificantly in an efficient and sustainable manner.

IntroductionHandling of oscillations, or instabilities, in oil- and gas

production systems is of high priority for operators of manyfields. The reason being associated profit-reducing issues likeunplanned shutdowns, too much flaring, increased

maintenance, off-spec production, metering problems, etc.An oil- and gas production system consists of one or more

reservoirs, a production gathering system (wells/flowlines/pipelines), processing facilities, export facilities,associated instrumentation and controls, and a control systemwith a certain configured control logic. Its dynamical behavior

depends on the combined state of all its components, or subsystems, as well as how it is operated. Sorting out what is the

root-cause of oscillations present in the system, let alone find aremedy, is therefore generally a very challenging task.

Tracking down prime suspects might in some cases be easy,while fixing the associated operational problems might be veryhard and/or expensive. In other cases, it might be very hard tofind the cause, while the fix is easy. For example, spotting that

a pipeline or well is slugging, that is, producing liquids andgas intermittently, is often easy based on appropriate pressure

and temperature readings. However, handling the problem properly might be very challenging. On the other hand might it be hard to spot that a level- or pressure control valveexperience stiction and moves in jumps causing pressures/levels/flows/temperatures to oscillate. However,fixing it might be easy. The same goes for the tuning of, forexample, a level controller.

In this paper it is presented a non-intrusive approach tohandling oscillations in oil- and gas production systems. Whenit comes to slug handling, it might be complementary to othermore conventional non-intrusive means, like choking andexcessive use of gas lift for stabilization, or it might replacethem. In any case it enables increased production. It might be

interpreted as slug management from a practical dynamicalsystems point-of-view. It has emerged as a result of providing

oil- and gas field operators with services and solutions withrespect to slug management since the late 1990’s. Theassociated base of experience includes hands-on experiencefrom approximately 20 fields—mainly in the North Sea. Theapproach consists of solutions for automatic control, or, active

feedback control, of well(s)/pipeline(s) and associated

SPE 96644

Active Slug ManagementO. Slupphaug, SPE, H. Hole, and B. Bjune, ABB



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separators as well as services for generic handling ofoscillations/instabilities including control strategy selectionand -tuning.

The paper is structured as follows: Firstly, an overview ofthe different activities associated with the approach is

presented. Secondly, overviews of associated control solutionsare presented. Before the conclusions at the end, some

example field results are provided.

Approach OverviewThe approach to oscillation handling advocated herein may bestructured into three activities:

Data gathering Data analysis Proposition- and planning of field work

Data GatheringThe goal of the data gathering activity is to gather sufficientdata/information that the cause(s) for the oscillations can beidentified in the analysis phase. It is necessary to get a full picture of the relevant part of the production system and its

associated control logic and operational procedures. It is oftenvery hard to know where to put the boundary for data

gathering—often it is most time efficient to gather more than possibly needed and discard what is not needed as the analysis proceeds. The following data/information is typicallycollected:

Logs of relevant tags (~ # 200-300) at 10 sec samplerate

Data sheets (control valves, pumps, compressors, hx) P&ID’s SCD’s (System Control Diagrams—if existing) PFD’s (Process Flow Diagrams) Dump of control logic (from the control system) Dump of database holding the controller settings Control narratives Overview of manual operations (the ones not

available in the datalogs)—discussions with key

personell in operationsOne lesson learned during the years is that the estimated timefor getting proper data logging in place and the proper datainto the office always is under estimated. An other observationoften made is that the control narratives—if existing at all— are very high level and does typically not include

considerations with respect to relevant disturbances to besuppressed nor handling of possible loop interactions and

nonlinearities—main issues to be aware of to be able tounderstand the observed oscillations. Yet another observationis that it is very often inconsistensies found in the controlstrategy shown in the P&ID’s, the one shown in the SCD’s,and the one actually used as shown in the dump of the controllogic. Furthermore, is it very important to discuss theoscillation nchallenges with experienced control room

operators. Their input is crucial in the analysis activity forquality assurance of the data as well as explaining operationsnot explicitly logged in the data. This includes opening andclosing of bypass valves, rerouting of wells, switching ofhydro cyclone packages, closing of block valves due toleaking control valves, integrity testing of wells, cleaning of

transmitters, etc.

At the end of the data analysis activity a detailed view ofthe relevant part of the production system, its instrumentation,its control logic, and its operational procedures is in place.This forms the basis for the analysis activity presented next.

Data analysisIn the data analysis activity a goal could be to provide a

prioritized list of remedies for handling the oscillations. A

different goal could be to answer whether a certain solution isfeasible and if it will cure the observed problems. In bothcases the result should be rooted in a proper, objective,analysis of relevant historical data. The data analysis typicallyinvolves analysing trends of hundreds of tags over a period of

a few months, typically sampled at 10 secs. Tools for doingthis efficiently are crucial. Furthermore, will the analysis often

involve carrying out dynamic simulations of the system. It isthen important that the underlying models are matched to thehistorical data. Also, in order to configure a proper simulationscenario, one need to fully understand the purpose of thesimulation including how to choose the boundary conditions— typically this requires extensive on-site practical experience.

The data analysis activity typically provides a list of possible remedies, with associated cost and benefit estimates,

to the oscillation problems analysed based on historical data.The proposed remedies can be categorized as follows:

Tuning of certain exising controllers Change of control strategy

Active control of selected wells/pipelines Active slug mitigation

Change of operating conditions Change of operating procedures

Based on the above one carries on to the next phase if anyremedies have been found.

Proposition- and planning of field work

From the list of possible remedies one typically choose the“lowest hanging fruits” first. This should be done in close

cooperation with operations so as to ensure ownership to thechosen remedy in the on-site operations organization. This

typically gives a smooth and efficient implementation andhand over of the remedy to operations. Also, it creates a basisfor efficient follow-up.

Slug Management Solutions OverviewAs shown in Figure 1 solutions for slug management based on

active control may be structured into solutions for wellcontrol, solutions for pipeline control, and solutions for slug

mitigation by utilizing buffering capacity in the processingfacilities. Common for all solutions are functionalities forhandling of non-linearities, decoupling of dynamicinteractions, as well as some sort of transient flow estimationsufficiently accurate for control purposes. Next a briefcharacterization of each solution is given.

Active Flowline Control

By active flowline control we refer to a control solution whichactively manipulates the flowline outlet control valve or choke based on properly chosen measurements in the pipeline andthe downstream processing facilities. Typically, the main goalis to provide operations with the possibility of operating at thehighest possible average valve/choke opening or at the lowest

possible wellhead platform (or, subsea manifold) backpressurewithout causing shutdown or overload of the downstream



SPE 96644 3

processing facility. A possible layout for so-called activeflowline control is shown in Figure 2.

Active Well ControlActive well control is basically active flowline controlscounterpart for control of wells and by active well control we

refer to a control solution which actively manipulates thewellhead amd/or gas-lift choke based on properly chosen

measurements in the well and the downstream processingfacilities. Typically, the main goal is to provide operationswith the possibility of operating at the highest possibleaverage choke opening or at the lowest possible wellhead- or

downhole pressure without causing shutdown or overload ofthe downstream processing facility.

Figure 4 illustrates the different functionalities included inthe solutions for active flowline control and active wellcontrol. As can be seen there are modules for stabilization ofthe flow in the pipeline/well, avoiding overload of

downstream facilities, support of ramp-up, pro-active slugreception, and monitoring of the well/pipeline state.

Active Slug Mitigation

Active slug mitigation refers to a control solution whichmitigates flow variations through the processing facilitites.This requires controlling at least one of the inlet separator(s)outlet valves. It is typically integrated with active well controlor active flowline control. This way one gets an integrated

well/pipeline separator control strategy, meaning that one cancoordinate the control of the both the inlet and the outlet of theseparator so as to increase the maximum possible average pipeline/choke opening or minimize the possible associated backpressures even more than with out such an integration(while avoiding overload of the separator and possibly other

downstream equipment). An example layout is shown inFigure 5.

Field ExamplesWe have included three field examples to illustrate the potential benefits of the above described approach and itsassociated solutions. Common for all these examples is a verytight cooperation with the on-site operations team as well asthorough preparations based on historical data.

Field Example 1

Figure 5 and Figure 6 basically documents the effect of activeslug mitigation combined with active flowline as advocated

herein compared to a different slug mitigation scheme with thesame goal of maximizing the average pipeline outlet chokeopening.

Field Example 2Figure 7 and Figure 8 document that it is indeed possible tostabilize the flow of well using active well control based on

the downhole pressure.

Field Example 3Figure 9, Figure 10, and Figure 11 illustrate that proper tuningof a degassing drum level controller can increase the watertreatment capacity of a processing facility by 6%, which was amajor benefit since it was constraining the production. In this

case it is interesting to note that the main focus was on thewells and the inlet separator control in the beginning of theanalysis.

ConclusionsThe presented non-intrusive approach to handling oscillationsin oil- and gas production systems—which might beinterpreted as slug management from a practical dynamicalsystems point-of-view—has proven to enable substantial

increased production using the different associated means.Success criteria include; (1) thorough preparations in form

gathering data and information so as to get a complete pictureof the production system with its associated actual controllogic, instrumentation, and operational procedures; (2) dataanalysis using proper tools and with involvment from

experienced personell from operations for quality assurance;(3) planning of on-site work realizing the potential of the“lowest hanging fruits” first, again with involvement fromoperations.

Figure 1 Different solutions and services associated with a non-intrusive approach to slug- and oscillations management.

L

P

z

Separator

P

P

F

AFC

P

Figure 2 Possible layout for active flowline control. The flow outof a pipeline tying a wellhead platform to a processing platform iscontrolled. The measurements used are the wellhead platformdeparture pressure, the pressures up- and downstream thepipeline choke and the pressure and oil level of the receivingseparator. Based on these measurements the choke iscontinuously activated so as t o attempt stabilizing the flow in thepipeline while avoiding overloading the downstream separator.



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Figure 3 Possible layout for active well control of a gas lifted well.Measurements used are the gas-lift annulus pressure, thedownhole pressure, and the pressures up- and downstream theproduction c hoke.

Figure 4 Functionality overview for active flowline- and wellcontrol.

Figure 5 Field Example 1: Active slug mitigation. Showingmeasurements (blue) and control s (red).

Blue – Inlet choke

Red – Oil flow

Yellow – Oil level

Switching control strategy

Figure 6 Field Example 1: Comparison of two different controlstrategies for slug mitigation. The one to the right is the onerecommended herein. In this case it resulted in a 3.5 % increase inliquid production compared to the one in place at the time of the

trial. In addition the separator oil level excursions weresignificantly reduced.

Figure 7 Field Example 2: Active well control. Instrumentation andwell geometry.

2 2.2 2.4 2.6 2.8 3 3.2 3.4 3.6 3.8 474

76

78

80

82

84

86

88

Time [days]

Brage Active Well Control Field Test (Day 0 = 24-Aug-2001 07:59:00)

Starting active control

Days

Figure 8 Field Example 2: Result of active control of the well.Downhole pressure is stabilized and reduced in a controlledmanner. In this case the well was impossible to produce with outthe stabilizing controller.



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Figure 9 Field Example 3: Initial distribution of flow rate throughdegasser.

Sammenheng mellom ventilåpning og vannrate, ventil til sjø

y = 0,003x3 - 0,1749x

2 + 4,8379x - 5,2632

-200

0

200

400

600

800

1000

1200

0 10 20 30 40 50 60 70 80 90 100

0209 - 0409

2308 - 2408

Poly. (0209 - 0409)

Figure 10 Field Example 3: Installed control valve characteristic.Gain is increasing with increasing valve opening and throughput.X-axis is valve opening, y-axis is throughput in m3/h. PIDcontroller tuning at low openings results in os cillatory behavior athigh openings.

Figure 11 Field Example 3: Final distribution of flow throughdegasser. The flow variance reduction enabled a 6% increase inthe constraining water treatment capacity since the active

constraint was on the pressure safety valve flow capacity for thedegasser.

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Active Slug Management