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Home / Issue Archive / 2006 / October #10 / Long Distance Multiphase Flow: R&D History and Key Applications

№ 10 (October 2006)

Long Distance Multiphase Flow: R&D History and Key Applications

Statoil and others have long prophesied that the North Sea would become a mature hydrocarbon province, and that the majority of new discoveries would be too small to be developed as stand-alone fields.

By Sven Klemp, Per Fuchs, Anthony Buller

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If this came true, it would mean that small North Sea accumulations could only be profitably exploited if linked (tied-back) to the expanding infrastructures of major producing fields; significant finds in areas lacking infrastructure might have to be linked directly to onshore plants; and major discoveries would probably be located in remote, deepwater regions elsewhere on the Norwegian shelf.

Each of these postulations had one thing in common: the ability to transfer untreated well-streams over considerable distances. Statoil invested large sums of money in flow assurance research and development – an inspired decision that paid off handsomely because this prophesy has largely come true:
• Numerous small (satellite) fields have indeed been tiedback to established offshore production infrastructures and field centers.
• Hydrocarbons from seafloor (sub-sea) wellheads are conducted to floating production facilities via extensive subsea flow-lines and risers.
• Multiphase well-streams from gas and condensate fields are transferred to onshore processing plants for subsequent processing and export.

Research History

Statoil’s engagement in flow assurance research dates back to 1980 when the Institute for Energy Technology (IFE) proposed the joint development of a pioneering, transient, twophase computer model for predicting and simulating the simultaneous flow of oil and gas in pipelines. A little later, SINTEF, supported by oil companies (including Statoil), started work on a large-scale flow laboratory at Tiller outside Trondheim – an impressive facility useful for generating data for computer modelling.

Statoil was also active in a host of additional projects concerning, for example, PVT simulation, chemical treatment and multiphase flow equipment.

Then, in 1993, Statoil gave flow assurance a major boost by launching its five-year “Statoil Multiphase Development Program” in association with IFE, SINTEF and several vendors, including Scandpower. A complementary joint venture (SSH) was also established during this time between the three Norwegian oil companies, Statoil, Saga and Norsk Hydro. The objective was to collectively improve their understanding of the entire breadth of multiphase transport technology.

Later, and as a direct consequence of the authorities’ Norwegian Deepwater Program (NDP) initiative, Shell joined forces with Statoil to develop our most recent flow simulator for deepwater applications. With the subsequent participation of Norsk Hydro, the SSH cooperation comprised Statoil, Shell and Norsk Hydro as the main players.

Throughout these various relationships, a significant part of the work was carried out at Statoil’s Research Center in Trondheim, much of it involving novel laboratory experiments and field measurements. And now, some twenty or so years later, Statoil is regarded as one of the world’s leading flow assurance exponents.

Technical Considerations

The basis for effective multiphase transport and design lies in high quality well fluid characterization, advanced fluid mechanics and flow simulation tools, and last, but not least, in-depth understanding of the fluid behaviour.

Numerous complications arise from liquid slugging and produced sand transport, and the simultaneous occurrence of physicochemical flow-impeding phenomena such as wax, gas hydrates, scale, asphaltenes and emulsions. Carbon dioxide (CO2) and hydrogen sulphide (H2S) reservoir gases also create noxious chemical mixtures which can seriously corrode hardware. All of these aspects have to be well understood if engineers are to make reliable predictions of their occurrence and implement the best ways of preventing and treating them. Developments in pressure boosting equipment, flow meters and other hardware devices also have to be addressed, thus adding to the overall complexity of flow assurance technology.

Multiphase transport systems are as diverse as the reservoirs they serve: fluid compositions, pipeline lengths, diameters, routes and seafloor topography vary from case to case. Even so, it is possible to divide them into two main classes. The major challenge for oil systems is the accurate prediction of falling pressure (pressure drops) along pipelines, properly taking fluid properties (rheology) into account (e.g. the oil-water flow regime, emulsification and viscosity). These aspects are vital for selecting optimum pipeline diameters, establishing adequate thermal insulation design, and ensuring that receiving inlet separators are properly dimensioned to receive liquid surges. For gas/condensate systems, it is important to predict the volumes of condensate and water accumulating in a pipeline (liquid inventories) and the severity of liquid surges arising from increases in flow rate and/or pipeline pigging. Such predictions are especially needed for designing slug-catchers, which are high pressure, liquid receiving and storage facilities normally located onshore, and evaluating the impact of liquid surges on downstream processing plants and operations.

Multiphase Flow Simulators

Much of the accumulated wealth of knowledge, experience and experimental information has been synthesized in the form of numerical tools. These tools range from simple, empirical correlations to extremely complex, rigorous, mathematical models and computer programs. Multiphase flow simulators are currently based on one-dimensional, “mechanistic” flow models (i.e. the flow is described by mathematical equations which conserve mass, momentum and energy in time and space and attempt to capture the physical mechanisms governing the various phases). However, to solve these equations it is necessary to rely heavily on empirical correlations – closure relations – based on relevant experimental data. Closure relations largely concern interactions between phases, phase mixing, and inter-phase momentum exchange. Obviously, experimental loops cannot exactly reproduce field conditions, no matter how advanced they are. Flow models must therefore be thoroughly tested against reliable and representative field data. Statoil has accordingly gathered an extensive body of information from its own fields.

Over the years, simulators have undergone considerable development. For example, Statoil and other companies have continually improved OLGA – today’s industry standard. Commercialized by Scandpower in 1999, the latest version (OLGA2000) is designed to simulate steady-state and transient multiphase flows in wells and pipelines. It is capable of handling any combination of multi-component hydrocarbons and produced water, and can also deal with single phase flow. More specifically, OLGA is used to efficiently and accurately simulate, analyse and optimize an impressive array of well-stream transport operations and phenomena, and is thus applicable to a wide range of system operations. It also fulfils the functional requirement for more challenging applications related to deepwater developments, multiphase flow networks, multi-lateral (branched) wells and extremely long, multiphase pipelines. Today, it is fair to say that OLGA2000 have cornered the dynamic multiphase flow simulator market.

Tracer Techniques Used to Measure Liquid Accumulation in Multiphase Gas-Condensate Pipelines

In reservoir studies small quantities of harmless radioactive materials or chemicals are sometimes added to injection water to accurately trace the passage of fluids towards production wells. Statoil and IFE have taken this a step further by adapting tracer techniq ues to measure liquid accumulations in multiphase flow pipelines. This is important because the volumes of liquid phases (water and condensate) can be crucial for the design and operation of multiphase pipelines and receiving facilities, and for the calibration of numerical models, such as OLGA, which are designed to simulate and predict the behaviour of the physical mechanisms involved in pipeline flow and the tracking of individual slugs. The overall objective is to better control the outflows to optimize operations and production regularity. Such studies were previously carried out in a rather crude and cumbersome fashion using pigs; but this is about to change by introducing the new technique, which is elegant in its simplicity. Basically, condensate and produced water are first laced with separate tracers (radioactive or chemical) at the inlet to a pipe. Fluid samples are then taken at regular, closely spaced intervals at the outlet to measure the times the tracers have taken to travel through the pipeline and their concentrations. The results are translated into residence times and liquid volumes. Successful tests have now been carried out on the Huldra-Heimdal, Midgard-?sgard and Troll-Kollsnes pipelines, showing that condensate and aqueous hold-ups can be unobtrusively measured separately and accurately without hindering production. Having filed a patent to protect the innovation, Statoil is considering the development of continuous, online monitoring using chemical tracers and eventual commercialization.

Applications: Long Distance Multiphase Gas-Condensate Pipelines

In a gas/condensate pipeline, the volume of liquid being accumulated depends strongly on the operating conditions. For example, if the flow rate is maintained at about the level for which a pipeline is designed (the design flow rate), liquid transport is normally efficient; some of the liquid will even be transported in the form of droplets in the gas core. Condensate and water will also be well mixed and flow at the same speed. Under such conditions, the liquid content in a pipeline will be modest.

However, if the gas production rate is lowered, friction between the gas and the liquid becomes less effective and the liquid content starts to rise. Initially the increase is small, but at some stage droplet transport vanishes and the liquid content begins to build up significantly. Then, as the gas production rate falls even further, condensate and water no longer mix. When this happens, interaction between the two liquids is poor, and the water content as well as the total liquid content increase abruptly. (This normally happens when the gas production rate falls to below about 50 percent of the design rate.) In addition, the critical liquid fraction is usually higher the longer a pipeline becomes, because the diameter of long distance pipelines is often greater than short distance pipelines to avoid excessive pressure drops. If the flow rate is then raised, excessive liquid accumulations must be expelled. Long distance gas/condensate pipelines are therefore normally equipped with large slug catchers.

A good example of liquid inventory management concerns the two, parallel, 65 km long and 36-in. nominal diameter pipelines linking the Troll A platform to onshore receiving facilities at Kollsnes, at the west coast of Norway. Each pipeline is designed for a gas production rate of some 50 mln standard cub. m per day, and both are equipped with a common slug-catcher capable of accommodating a maximum of 2,400 cu. m of liquid. However, operational tests showed that the water content in the pipeline would exceed the water receiving capacity of the slug-catcher when one pipeline is producing at a steady state of 35 mln standard cu. m per day. The liquid inventory is thus controlled by intermittently increasing the production rate to force liquid out of the pipeline.

Another example is the approximately 140 km long pipeline planned to lead well-stream from the Sn?hvit field to onshore facilities on the island of Melk?ya, outside Hammerfest in northern Norway. The pipeline’s nominal diameter is about 28 in., and the slug-catcher is being designed to accommodate 800 cu. m of water and 1,900 cu. m of condensate. If the gas-liquid separation volume is also taken into account, the total volume reaches about 3,000 cu. m. Again, this is significantly less than anticipated volumes accumulating in the pipeline if the continuous production rate is low. The Sn?hvit pipeline feeding the Melk?ya Liquified Natural Gas (LNG) plant will be operated at sufficiently high, continuous flow rates. In such cases, it is necessary to establish a lower flow rate limit, known as the pigging limit. Above the limit, the system may be operated relatively freely, but there may be limitations on how fast the production rate can be increased. Below the limit, the system will require regular pigging for liquid inventory management. The Sn?hvit field will need to be operated without pigging because it will be a 100 percent subsea development.

Today, Statoil is the operator of approximately 900 km of offshore multiphase pipelines offshore in Norway:

• The 53-km 20-in. Midgard to ?sgard B pipelines (1999).
• The two 67-km long 36-in. pipelines connecting the giant Troll field to the onshore Kollsnes gas treatment and gas export plant (1996).
• The 140-km 22-in. pipeline from the minimum processing Huldra platform to the Heimdal gas platform (2001).
• The 85-km 18/20-in. Mikkel subsea tie-back to the Midgard subsea template (and further on to the ?sgard B gas platform) (2003).
• The 145-km 30-in. wet gas pipeline from the Kvitebj?rn platform to the Kollsnes gas plant (2004).
• The 143-km 28-in. well-stream transfer pipeline from the Sn?hvit subsea installations to the Melk?ya onshore LNG plant (2007).

Statoil is also responsible for the design and construction of the 100-km 32-in. multiphase pipelines from the offshore South Pars phases 6, 7 and 8 platforms in Iran to be started up in 2007.

The experience gained from the design and operation of all these lines is of utmost importance in the planning, design and operation of future ultra long gas/condensate multiphase pipeline systems.

It is fair to say that Statoil has made a substantial contribution to offshore field development concepts involving solutions that would have been unheard of a few years ago. Statoil clearly intends to stay out in front also in the future within the area of multiphase technology and flow assurance together with old and new associates who share the same views and ambitions.


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