SPE PP. Active Slug Management Olav Slupphaug/SPE,ABB, Helge Hole/ABB, and Bjørn Bjune/ABB

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1 SE Active Slug Management Olav Slupphaug/SE,ABB, Helge Hole/ABB, and Bjørn Bjune/ABB Copyright 2006, Society of etroleum Engineers This paper was prepared for presentation at the 2006 SE Annual Technical Conference and Exhibition held in San Antonio, Texas, U.S.A., September This paper was selected for presentation by an SE rogram Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of etroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Society of etroleum Engineers, its officers, or members. apers presented at SE meetings are subject to publication review by Editorial Committees of the Society of etroleum Engineers. 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Box , Richardson, TX , U.S.A., fax Abstract Slug flow, or instabilities, in multiphase wells and -pipelines feeding oil- and gas processing facilities may cause operational challenges related to avoiding unplanned partialor complete shutdowns, satisfying flaring volumes, managing sand production, maintaining on-spec production, proving of fiscal 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 these conventional approaches imply inefficient production or expensive over-design. In this paper, a different from choking and use of gas lift for stabilization non-intrusive approach to slug management in wells and pipelines is presented. However, it will typically be complementary to other means, like choking and excessive use of gas lift, of handling slug flow challenges. The approach also applies to handling challenges related to oscillations and transients in the total production system, not only in the wells and pipelines. It may be interpreted as slug management from a practical dynamical systems point-of-view. It has emerged as a result of providing oil- and gas field operators with services and solutions with respect to slug management since the late 1990 s. The associated base of experience includes hands-on experience from approximately 20 fields mainly in the North Sea. The approach consists of solutions for automatic control, or, active feedback control, of well(s)/pipeline(s) and associated separators as well as services for generic handling of oscillations/instabilities including control strategy selection and -tuning. Field results from application of the approach are included. The experience gathered during these years supports that 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 slug management. 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 our experience that operators who, as part of their slug management strategy, include an approach with characteristics similar to the ones summarized above, will improve operations significantly in an efficient and sustainable manner. Introduction Handling of oscillations, or instabilities, in oil- and gas production systems is of high priority for operators of many fields. The reason being associated profit-reducing issues like unplanned 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/flow lines/pipelines), processing facilities, export facilities, associated instrumentation and controls, and a control system with a certain configured control logic. Its dynamical behavior depends on the combined state of all its components, or sub systems, as well as how it is operated. Sorting out what is the root-cause of oscillations present in the system, let alone find a remedy, 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 very hard and/or expensive. In other cases, it might be very hard to find the cause, while the fix is easy. For example, spotting that a pipeline or well is slugging, that is, producing liquids and gas 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 valve experience 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, for example, a level controller. In this paper it is presented a non-intrusive approach to handling oscillations in oil- and gas production systems. When it comes to slug handling, it might be complementary to other more conventional non-intrusive means, like choking and excessive use of gas lift for stabilization, or it might replace them. In any case it enables increased production. It might be interpreted as slug management from a practical dynamical systems point-of-view. It has emerged as a result of providing oil- and gas field operators with services and solutions with respect to slug management since the late 1990 s. The associated base of experience includes hands-on experience from approximately 20 fields mainly in the North Sea. The approach consists of solutions for automatic control, or, active feedback control, of well(s)/pipeline(s) and associated separators as well as services for generic handling of

2 2 SE oscillations/instabilities including control strategy selection and -tuning. The paper is structured as follows: Firstly, an overview of the different activities associated with the approach is presented. Secondly, overviews of associated control solutions are presented. Before the conclusions at the end, some example field results are provided. Approach Overview The approach to oscillation handling advocated herein may be structured into three activities: Data gathering Data analysis roposition- and planning of field work Data Gathering The goal of the data gathering activity is to gather sufficient data/information that the cause(s) for the oscillations can be identified 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 often very 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 typically collected: Logs of relevant tags (~ # ) at 10 sec sample rate Data sheets (control valves, pumps, compressors, hx) &ID s SCD s (System Control Diagrams if existing) FD s (rocess 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 operations One lesson learned during the years is that the estimated time for getting proper data logging in place and the proper data into the office always is under estimated. An other observation often 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 be suppressed nor handling of possible loop interactions and nonlinearities main issues to be aware of to be able to understand the observed oscillations. Yet another observation is that it is very often inconsistensies found in the control strategy shown in the &ID s, the one shown in the SCD s, and the one actually used as shown in the dump of the control logic. Furthermore, is it very important to discuss the oscillation nchallenges with experienced control room operators. Their input is crucial in the analysis activity for quality assurance of the data as well as explaining operations not explicitly logged in the data. This includes opening and closing of bypass valves, rerouting of wells, switching of hydro cyclone packages, closing of block valves due to leaking control valves, integrity testing of wells, cleaning of transmitters, etc. At the end of the data analysis activity a detailed view of the 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 analysis In 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 is feasible and if it will cure the observed problems. In both cases the result should be rooted in a proper, objective, analysis of relevant historical data. The data analysis typically involves analysing trends of hundreds of tags over a period of a few months, typically sampled at 10 secs. Tools for doing this efficiently are crucial. Furthermore, will the analysis often involve carrying out dynamic simulations of the system. It is then important that the underlying models are matched to the historical data. Also, in order to configure a proper simulation scenario, one need to fully understand the purpose of the simulation 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 any remedies have been found. roposition- 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 the chosen remedy in the on-site operations organization. This typically gives a smooth and efficient implementation and hand over of the remedy to operations. Also, it creates a basis for efficient follow-up. Slug Management Solutions Overview As shown in Figure 1 solutions for slug management based on active control may be structured into solutions for well control, solutions for pipeline control, and solutions for slug mitigation by utilizing buffering capacity in the processing facilities. Common for all solutions are functionalities for handling of non-linearities, decoupling of dynamic interactions, as well as some sort of transient flow estimation sufficiently accurate for control purposes. Next a brief characterization of each solution is given. Active Flowline Control By active flowline control we refer to a control solution which actively manipulates the flowline outlet control valve or choke based on properly chosen measurements in the pipeline and the downstream processing facilities. Typically, the main goal is to provide operations with the possibility of operating at the highest possible average valve/choke opening or at the lowest possible wellhead platform (or, subsea manifold) backpressure without causing shutdown or overload of the downstream processing facility. A possible layout for so-called active flowline control is shown in Figure 2. Active Well Control

3 z L F SE Active well control is basically active flowline controls counterpart for control of wells and by active well control we refer to a control solution which actively manipulates the wellhead amd/or gas-lift choke based on properly chosen measurements in the well and the downstream processing facilities. Typically, the main goal is to provide operations with the possibility of operating at the highest possible average choke opening or at the lowest possible wellhead- or downhole pressure without causing shutdown or overload of the downstream processing facility. Figure 4 illustrates the different functionalities included in the solutions for active flowline control and active well control. As can be seen there are modules for stabilization of the flow in the pipeline/well, avoiding overload of downstream facilities, support of ramp-up, pro-active slug reception, and monitoring of the well/pipeline state. Active Slug Mitigation Active slug mitigation refers to a control solution which mitigates 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 control or active flowline control. This way one gets an integrated well/pipeline separator control strategy, meaning that one can coordinate the control of the both the inlet and the outlet of the separator 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 in Figure 5. Field Examples We have included three field examples to illustrate the potential benefits of the above described approach and its associated solutions. Common for all these examples is a very tight cooperation with the on-site operations team as well as thorough preparations based on historical data. Field Example 1 Figure 5 and Figure 6 basically documents the effect of active slug mitigation combined with active flowline as advocated herein compared to a different slug mitigation scheme with the same goal of maximizing the average pipeline outlet choke opening. Field Example 2 Figure 7 and Figure 8 document that it is indeed possible to stabilize the flow of well using active well control based on the downhole pressure. Field Example 3 Figure 9, Figure 10, and Figure 11 illustrate that proper tuning of a degassing drum level controller can increase the water treatment capacity of a processing facility by 6%, which was a major benefit since it was constraining the production. In this case it is interesting to note that the main focus was on the wells and the inlet separator control in the beginning of the analysis. Conclusions The presented non-intrusive approach to handling oscillations in oil- and gas production systems which might be interpreted as slug management from a practical dynamical systems 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 picture of the production system with its associated actual control logic, instrumentation, and operational procedures; (2) data analysis 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 from operations. Figure 1 Different solutions and services associated with a nonintrusive approach to slug- and oscillations management. AFC Separator Figure 2 ossible layout for active flowline control. The flow out of a pipeline tying a wellhead platform to a processing platform is controlled. The measurements used are the wellhead platform departure pressure, the pressures up- and downstream the pipeline choke and the pressure and oil level of the receiving separator. Based on these measurements the choke is continuously activated so as to attempt stabilizing the flow in the pipeline while avoiding overloading the downstream separator.

4 4 SE Switching control strategy Figure 3 ossible layout for active well control of a gas lifted well. Measurements used are the gas-lift annulus pressure, the downhole pressure, and the pressures up- and downstream the production choke. Blue Inlet choke Red Oil flow Yellow Oil level Figure 6 Field Example 1: Comparison of two different control strategies for slug mitigation. The one to the right is the one recommended herein. In this case it resulted in a 3.5 % increase in liquid production compared to the one in place at the time of the trial. In addition the separator oil level excursions were significantly reduced. Figure 4 Functionality overview for active flowline- and well control. Figure 7 Field Example 2: Active well control. Instrumentation and well geometry. 88 Brage Active Well Control Field Test (Day 0 = 24-Aug :59:00) 86 Starting active control Time [days] Days Figure 5 Field Example 1: Active slug mitigation. Showing measurements (blue) and controls (red). Figure 8 Field Example 2: Result of active control of the well. Downhole pressure is stabilized and reduced in a controlled manner. In this case the well was impossible to produce with out the stabilizing controller.

5 SE the constraining water treatment capacity since the active constraint was on the pressure safety valve flow capacity for the degasser. Figure 9 Field Example 3: Initial distribution of flow rate through degasser. Sammenheng mellom ventilåpning og vannrate, ventil til sjø y = 0,003x 3-0,1749x 2 + 4,8379x - 5, oly. ( ) 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. ID controller tuning at low openings results in oscillatory behavior at high openings. Figure 11 Field Example 3: Final distribution of flow through degasser. The flow variance reduction enabled a 6% increase in