Pigging of a multiphase (i.e. liquid/gas) pipeline can result in a large "pigged" liquid slug when a normal (i.e. non-by-pass) pig is used. This requires a large separator or slugcatcher, or otherwise accepting production deferment during pigging. These problems can be avoided by using a by-pass pig, which means that part of the gas can by-pass the pig through holes, which reduces the pig velocity and in turn it also reduces the pig-generated volume. By-pass pigging is applied more and more often, but it remains difficult to select the right by-pass opening for the initial pig run. This paper describes a simple design tool, based on steady-state hydraulic pipeline simulation results, to determine the required fixed by-pass opening. Also field experience with a speed control pig for a gas-condensate pipeline is shown (i.e. the by-pass opening is adapted along the pipeline to maintain a constant pre-set pig speed). The by-pass pigging design tool is based on steady-state hydraulic pipeline simulations. By-pass design has two main constraints: (1) too small an opening will create a large Pig-Generated Volume (PGV), and (2) too large an opening will create too little force on the pig to overcome the wall friction. The optimum opening is when the liquid surge will be minimum, to avoid having the risk that the pig gets stuck. The main uncertainty in the prediction is the friction between the pig and the pipe wall. The simple steady state by-pass pigging design tool is validated against both dynamic simulation results and field data. The tool provides a quick method to assess the right by-pass opening without the requirement of doing an extensive dynamic simulation study. As the pressure decreases along the pipeline, the optimum by-pass opening also varies along the pipeline; the gas velocity and therefore the pig velocity will normally increase towards the outlet of the pipeline and a larger by-pass would be preferred at this point. However, a (fixed) larger by-pass can cause difficulties when launching the pig. A speed control pig consists of a variable by-pass valve which is controlled in such a way to maintain a constant pig velocity. For example, when the by-pass opening is reduced, the pressure drop across the pig increases and therefore the pig velocity increases as well. The speed control pig has been used several times for a 70 km long gas condensate pipeline, which has successfully reduced the liquid surge into the slug catcher. Field data demonstrate that the by-pass pig speed can be maintained almost at a constant velocity, when using a speed control pig for a gas condensate pipeline.

In mature fields, wells and pipelines are often oversized for the current operating conditions. This is because they have been primarily designed to handle early and midlife production, which may lead to slugging issues in later field life. The resulting flow fluctuations frequently lead to liquid handling problems caused by excessive liquid levels and pressure surges in the first stage separator. This can be an important source of downtime due to facility trips and deferment from sub-optimal facility operations. Furthermore, slugs travelling through topside piping can cause integrity issues when they impact bends.In flowline-riser systems, riser-induced slugging can lead to large slugs, especially in deepwater systems. These can usually not be contained in a platform-based separator. In such cases gas lift and conventional choking are often used to mitigate slugging. These two methods have drawbacks, however. For gas lift a source of compressed lift gas must be connected to the riser base and the volumes required to mitigate slugging may cause constraints in gas handling. Conventional choking leads to production deferment due to the backpressure imposed by a partially closed choke.In recent years "active" slug control methods have been developed to overcome these drawbacks. One such system is a relatively inexpensive solution developed by Shell Global Solutions* known as the Smart Choke. This system has been installed at several locations worldwide and has been proven to be very effective in stabilizing slugging in flowlines and risers. Here, the topside choke is actively controlled to mitigate riser-induced slugging and acts only if flow surges are observed, reducing the peak flow rate into the separator. Between slugs, the choke opens, reducing the imposed backpressure. Since flow fluctuations are reduced, a flowline can be operated at higher average flow rate as the topside facilities can be operated at higher throughputs without risking excessive separator liquid levels. Field data from case histories in the GOM, Malaysia and Nigeria indicate that production gains of 10% are often possible.This paper presents the modeling, implementation and the data obtained from operations of the Smart Choke implementation for a deepwater facility in Nigeria. The objective of the Smart Choke is to stabilize * Shell Global Solutions is a network of independent technology companies in the Shell Group. In this document, the expressions "Shell" or "Shell Global Solutions" are sometimes used for convenience where reference is made to these companies in general, or where no useful purpose is served by identifying a particular company.the flow from the riser and to reduce the gas lift requirement. A feasibility study was performed to analyze the slugging behavior of the pipeline and the impact of no control, gas lift and, the combination of gas lift and Smart Choke. Upon favorable modeling results, the Smart Choke was moved to the project stage and implemented. Field data are presented to demonstrate how the Smart Choke was able ...

In mature fields, pipelines are often oversized for their operating conditions. This is because their design was primarily based on the early and plateau production and less on late life production. This oversizing may lead to slugging issues, whereby flow fluctuations cause liquid handling problems in the receiving facilities, which can lead to system trips. The purpose of this paper is to describe the workflow, which includes identifying the operational problems, designing the slug control system, and commissioning and monitoring of the control system. The Smart Choke developed by Shell1 is able to mitigate the effects of slugs and has now been installed at several locations worldwide. It is an active slug control system: the topside choke acts only if surges are observed, reducing the peak flow rate into the separator. Between slugs, the choke valve opens, reducing the imposed backpressure. Since flow fluctuations are reduced, operation is again possible without risking excessive separator liquid levels. The workflow consists of the following steps: (i) If slugging leads to production deferment or to operational problems, a feasibility study is done to assess the benefits of installing a Smart Choke. To this end, the key design and production data are collected in a single data sheet that is analyzed by flow assurance experts, (ii) The analysis may include using dynamic multiphase flow models. The models are used to reproduce the slugging behaviour as seen in the field and to assess the adequacy of the Smart Choke. (iii) If the results indicate a positive outlook, and the asset agrees, the implementation needs to be planned and executed. This requires further data gathering on the choke actuator, the pipework for a suitable transducer location, and the platform control system. (iv) The flow assurance and process control experts go to the platform to help commissioning the Smart Choke, which includes tuning of the controller parameters. (v) Once in operation the Smart Choke performance is monitored remotely by the experts using PI Process Book. In addition to pipeline systems already in operation, implementation of a Smart Choke can also be considered for pipeline projects in the development phase. When in the hydraulic assessment risks are identified with respect to slugging, the decision for full implementation can be postponed, but the production system is made "Smart Choke ready" by reservation of weight/space at a pipe segment at the outlet of the pipeline upstream of the separator. When slugging occurs in a later phase of the field life the spool piece can be replaced by the required Smart Choke hardware without doing any hot work.

Description Large fluctuations in gas and/or liquid production can lead to major disruptions on the topside facilities. These fluctuations are caused by the fluid composition, geometrical layout and operating conditions of the production system. With the current trends of: Producing marginal gas/condensate and oil fields to existing facilities with subsea tie-backs, Developing more deepwater fields, Producing from existing production facilities towards the end of field life cycle, irregular production or slugging pipeline systems are observed more frequently. Therefore, slug mitigation techniques may achieve significant value impact on the business. The most recent technology in Shell for slug control is the Smart Choke. This technology consists of a single control valve that is installed between the riser top and the first stage separator. It is an active slug control device acting on gas and liquid surges without the requirement of phase separation upstream of the control valve. The basic control mechanism maintains a constant total volumetric flow at the system outlet. Furthermore, a detection algorithm is incorporated, which detects 'liquid only' or 'gas only' production. Based on this, the controller will switch between the different control modes for slug control. Additional to this flow controller, a slow valve position controller and a differential pressure override controller is used to ensure that the output of the volumetric flow controller remains in the range of the normal (or desired) operating valve position.

Objectives/Scope One of the main objectives of the wells, reservoir and facilities management (WRFM) is to reduce production decline caused by falling reservoir pressure and water breakthrough. Traditional WRFM efforts focus on well interventions; however, facilities optimization can also help to maintain production levels, as has been demonstrated in Shell's Sarawak gas asset in Malaysia, where various measures have led to a total of over 50 Bscf of additional gas production over a period of several years for investments less than $1 million per year. Methods, Procedures, Process The Sarawak asset is a complex production network of 14 producing gas fields with 3 manned offshore gas-processing hubs, 7 unmanned platforms and 3 subsea installations. The gas network is producing below its plateau production level. The below capacity production leads to slugging in pipeline-riser systems and wells and creates large liquid hold-ups in pipelines. Water production from wells is increasing. To maximize current production and extend production further into the future, a structured exercise to optimize the upstream facilities was started. Unnecessary pressure drops were eliminated, pigging procedures optimized, and slug and water control methodologies implemented. Results, Observations, Conclusions Any location where a pressure drop occurs in the process is a potential opportunity for optimization. Opportunities were found in inlet separators, at the compressor suction sides, water handling capacity and platform export locations. A novel implementation led to a floating pipeline export pressure matching the pipeline operating pressure to maximize production. Pigging with large liquid hold ups often incur production deferment by cutting production before pig launch or closing the slugcatcher inlet when the liquid comes in. Bypass pigging has been deployed in 7 production lines to fully eliminate deferment. Shell Sarawak Berhad (SSB) has been making effective use of Shell's proprietary Smart Choke slug control technology to allow pipeline-riser systems to operate far below their minimum turndown rate. It has now become the first company to adopt the technology directly on a well head to lower the impact of slugging from a well. Dynamic models of multiphase flow pipelines have been built to extend the production cut-off date by lowering the minimum operational flow rate through a combination of operational changes and novel technologies validated by field tests. Novel/Additive Information This paper demonstrates the production gains which can be achieved by doing a relatively small investment. The focus lies on facility optimization (part of WRFM) through a process of continuous improvement of proven technologies. A good example is increasing the operating envelope for Shell's Smart Choke slug control system from pipeline-riser systems to wells applications.