Flow-Assurance Modeling: Reality Check and Aspects of Transient Operations of Gas/Condensate Pipelines
- Lars Hagesaether (Statoil ASA) | Knud Lunde (Statoil ASA) | Frode Nygård (Statoil ASA) | Havard Eidsmoen (Scandpower Petroleum Technology)
- Document ID
- Society of Petroleum Engineers
- SPE Projects, Facilities & Construction
- Publication Date
- March 2007
- Document Type
- Journal Paper
- 1 - 17
- 2007. Society of Petroleum Engineers
- 4.1.2 Separation and Treating, 4.3.1 Hydrates, 4.2 Pipelines, Flowlines and Risers, 5.4.2 Gas Injection Methods, 5.3.2 Multiphase Flow, 4.2.3 Materials and Corrosion, 5.6.5 Tracers, 5.5 Reservoir Simulation, 5.2.1 Phase Behavior and PVT Measurements, 3.4.1 Inhibition and Remediation of Hydrates, Scale, Paraffin / Wax and Asphaltene, 4.1.5 Processing Equipment, 4.6 Natural Gas, 4.6.2 Liquified Natural Gas (LNG), 4.5 Offshore Facilities and Subsea Systems, 4.1.6 Compressors, Engines and Turbines, 4.1.3 Dehydration, 4.2.2 Pipeline Transient Behavior, 4.3 Flow Assurance
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Statoil operates a number of gas/condensate pipelines in the North Sea. This paper focuses on experience gained from operation and simulation, up to and including the tail end, of the 150-km-long, 22-in. Huldra-to-Heimdal pipeline.
During initial production at Huldra, the liquid accumulation was higher than predicted by modeling. Additionally, liquid surge waves not found in simulations were observed at the receiving facility. These findings were challenging, resulting from very low-liquid surge capacity in the receiving facility, and the minimum flow rate was increased. Investigations were carried out to explain the observations, and it was determined that condensate carryover in the Huldra scrubber significantly influenced the condensate content in the pipeline. The pipeline has now entered the tail-end production phase. Because of the high liquid content at low production rates, water/monoethylene glycol (MEG) no longer reaches the receiving facility on a regular basis, causing local hydrate problems at Heimdal and a lack of MEG for reinjection. Simulations show that cyclic operation of the receiving facility will transport water/MEG out of the pipeline on a more regular basis. This change in operating philosophy was an available option that Statoil did not have to implement.
The traditional gas/condensate development had a process facility close to the field, and the fluids would be exported through a single-phase gas line and a single-phase liquid line. This involved expensive process facilities at remote locations (often offshore) and multiple pipelines. Since the 1970s, significant research efforts have been put into multiphase transport.
As the ability to design two-phase (gas and hydrocarbon liquid) pipelines advanced, it was sufficient to dehydrate the fluid close to the field, and the hydrocarbons were transported in a multiphase pipeline. This provided significant savings because of a simpler and smaller process facility and a single pipeline [e.g., Malaysia Liquefied Natural Gas (MLNG) in Malaysia (Inyang et al. 1995), Brunei Liquefied Natural Gas (BLNG) in Brunei, Sable Island in Canada, and Nam Con Son in Vietnam]. The last step in the development has been the ability to design three-phase pipelines (gas, hydrocarbon liquid, and water), which was achieved in the early 1990s. This completely removes the need for the process facility, which is replaced by simple wellhead platforms as in Huldra (Hagesæther et al. 2003; Postvoll et al. 2002) and Troll in Norway (Klemp et al. 1997), South Pars in Iran, Ras Laffan and Qatar Gas in Qatar, and Goldeneye in the U.K. or complete subsea developments as in Mensa (Gilchrist nd Kluwen 1998) and Canyon Express in the U.S. (Wallace et al. 2001; Cooley et al. 2003), Scarab/Saffron in Egypt (Harun et al. 2002), the Troll-Oseberg gas-injection (TOGI) project (Lingelem et al. 1992), and Snøhvit and Ormen Lange in Norway (Wilson et al. 2004). Table 1 and Fig. 1 summarize the development of gas/condensate pipelines by some of their key parameters, such as pipeline diameter, length, two-phase vs. three-phase, and development by wellhead platform vs. subsea development. The present trend is that almost all pipelines are three-phase, and most are subsea developments unless the water is shallow.
The main issues considered when designing gas/condensate systems are usually pressure drop, liquid handling, and hydrate prevention. Pipeline-pressure drop is mainly related to selection of the correct pipeline size, while liquid handling relates to slug catcher size and plant liquid-processing capacity. A large-diameter pipeline usually will give a low-pressure drop but a high liquid content, causing liquid-handling problems, while a smaller-diameter pipeline will give a higher pressure drop but less liquid content. In addition, liquid handling and hydrate prevention are closely tied to the operational procedures of the pipeline for operations such as rate changes, shut-in and startup, blowdown, and pigging. Other potential issues considered are corrosion, wax deposition, and erosion.
Even with proper pipeline modeling during the design phase, there are still uncertainties in the simulation results. This paper summarizes some of the experiences from modeling and operation of gas/condensate pipelines. The simulation results are based on analysis using the multiphase pipeline simulation tool OLGAÒ (OLGA is a registered trademark of Scandpower Petroleum Technology, Norway 2001). Depending on the simulations, various features of OLGAÒ like slug tracking and compositional tracking have been used.
|File Size||3 MB||Number of Pages||17|
Cooley, C., Wallace, B.K., and Gudimetla,R. 2003. Liquid Management onCanyon Express. Paper SPE 84346 presented at the SPE Annual TechnicalConference and Exhibition, Denver, 5-8 October. DOI:http://www.spe.org/elibrary/servlet/spepreview?id=84346-MS.
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Klemp, S., Meland, B., Hustvedt, E.and Østby, O. 1997. Operational Experiences From Multiphase Transfer at Troll.Paper presented at the 8th International Conference on Multiphase, Cannes,France, 18-20 June.
Lingelem, M.N., Braseth, A.O., andHolm, H. 1992. Experience From Multiphase Flow Operations and PipelineOperation on TOGI. Presented at the Norwegian Petroleum Soc. Conference onMultiphase Transport, Røros, Norway, 20-22 September.
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Sira, T., et al. 2005. Liquidaccumulation in gas condensate pipelines measured by use of tracer techniques.Presented at the 12th Intl. Conference on Multiphase Production Technology,Barcelona, Spain, May 25-27.
Wallace, B.K, Gudimetla, R., and Saether,G. 2001. CanyonExpress Slugging and Liquids Handling. Paper OTC 13073 presented at theOffshore Technology Conference, Houston, April 30-May 3.
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