Summary
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.
Introduction
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.
© 2007. Society of Petroleum Engineers
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History
- Original manuscript received:
14 June 2006
- Revised manuscript received:
27 December 2006
- Manuscript approved:
4 January 2007
- Version of record:
20 March 2007
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