Remediating plugged subsea flowlines

Jeremy Lee
Tuesday, February 16, 2010

Remediating plugged subsea lines in deep and ultra-deepwater is dangerous and time-consuming and can become extremely costly if coiled tubing or wireline intervention is required to resolve the problem. Champion Technologies’ Jeremy Lee describes a process that can reduce the system pressure at the wellhead, thereby remediating hydrate blockages without requiring the support of an intervention vessel. The process also provides information on the composition and location of a production system blockage.

Flow assurance is the lynchpin of profitability for most offshore oil and gas projects. That is especially true for developments in deep and ultra-deepwater, where myriad types of blockages can form in subsea flowlines, jumpers, wellheads, or even wellbore tubing as a result of such fundamental factors as the composition of the production stream, operating conditions, errors in operating procedures, evolving well conditions, or countless combinations thereof. Even in wells that are being treated for hydrates, paraffin, scale or asphaltenes, it is still possible for plugs to occur in the production system if the correct treatment amounts are not injected and the required injection rates continuously monitored.

Deepwater producers know that removing plugs in subsea production systems can be extremely time consuming. Remediation costs, which include both the cost of intervention and the implied value of lost production, easily can run into millions of dollars. More importantly, some types of plugs in subsea production systems pose significant risks to employees, equipment and the environment. With subsea tiebacks being designed to traverse ever greater distances, the possibility of plugs forming beyond the reach of coiled tubing or wireline intervention is increasing daily.

Removing subsea blockages
Identifying the type of material creating a blockage and determining the size of the plug and where it is located in the production system is fundamental to developing an effective remediation strategy. However, so many factors can play roles in creating blockages that developing an effective remediation strategy is no easy matter.

Typically, plugs in deepwater are composed of hydrates and/or paraffin, although accumulation of sand/sediment or build-up of scale or asphaltenes can also cause blockages. In deep and ultradeepwater, blockages can occur due to instability of production chemicals injected subsea that have not been designed for temperatures and pressures on the seafloor. If the chemical products are not tested and qualified for subsea injection, they can cause blockage in the umbilical system, thereby preventing injection of the chemistry required to treat the well fluids and keep it flowing.

Hydrate plugs are especially troublesome, in part because they can form rapidly – in just a few hours – or take weeks or even months to form. In addition, hydrate plugs can become mobilized and burst piping, which poses a significant danger to personnel and the environment, alike. Paraffin plugs, by contrast, are more predictable because accumulations typically occur over long time periods.

The low-cost method of remediating blockages in subsea production systems derives from the exhaustive, comprehensive analytic processes developed by Champion to thoroughly diagnose the factors affecting oil and gas recovery rates of a given project, so as to assure selection of the best possible chemistry for each application. Key factors guiding the successful diagnosis and dissociation of plugs in subsea systems include:

  • characteristics of production stream components, including all hydrocarbon and non-hydrocarbon fluids and gases and contaminants produced from the reservoir or introduced through production operations;
  • well set-up, including piping configuration and diameters, equipment designs and capacities, and production component materials of construction;
  • field layout, including water depths traversed, tie-back distance, and bathymetry of the flowline;
  • operating parameters, including rates of production, production-stream composition, processing pathway, temperature and pressure regimes, and producers’ operating strategies; and
  • encyclopedic knowledge of oilfield chemistry acquired from over five decades of researching, designing, manufacturing, and deploying specialty chemical formulations for the upstream oil and gas industry.


Recent application
Champion recently used the low-cost plug remediation method to locate and identify the composition of a blockage in the flowline of a subsea well in about 2800ft of water in the Gulf of Mexico tied back to a steel-jacketed platform facility over 20 miles away in 450ft of water. The procedures and techniques used to lower the wellhead pressure, thus remediating the hydrate plug, were described in a technical paper presented at the 2009 Offshore Technology Conference (OTC 20171).

In that intervention, Champion first gathered information about the well’s operating parameters before the blockage occurred and its condition after the plug forced cessation of production operations, including the type of chemicals and produced fluids involved, the piping and valve configuration of the production system, production rates, chemicals being used to treat the well, and the diameters, lengths, volumes, pressures and temperatures of the system and its components.

Among other factors, Champion determined the salinity of produced water in the subsea flowline was only 6% and that reservoir gas was saturated with water vapor – a worstcase water chemistry scenario for water condensation and hydrate formation. Calculations indicated that for the system to be outside hydrate-formation conditions at the deepwater temperature of 40°F, flowline pressure would have to be reduced to about 650psi for 6% salinity water and 150psi for condensed water (Figure 1). The temperature and pressure profile of the system prior to the appearance of the blockage indicated the hydrate initiation point was within the first 1000ft of the flowline.

In addition, a series of procedures were performed to determine such parameters as the volume of liquid remaining in the flowline, the gas and liquid volume percentage occupying the well, and pressures remaining on various segments of well piping. Fluid height and liquid density was used to calculate the hydrostatic head pressure at the well head, which provided a basis for estimating the pressure on both sides of the hydrate blockage.

Once the location of the plug, its approximate size, and part of the composition was known, informed decisions could be made about the path forward in the remediation process. Based upon the parameter values calculated and configuration of the well set-up, Champion was able to formulate a process to dissociate the blockage by using the tubing volume between the production system’s process choke valve and the surface-controlled subsurface safety valve as a means of bleeding off pressure on the flowline (Figure 2). To successfully lower pressure in the flowline upstream of the plug, Champion had to repeat the process numerous times. The bleed-back operations were somewhat time-consuming because of the size of the bleed back line utilized, but remediating the blockage using this process does not require the more costly intervention.

Thoughts for the future
The procedures implemented to remove the plug were successful due to the well set-up and produced fluid characteristics. But pre-planning for a worst-case blockage scenario – for example, by slightly increasing the size of chemical treatment or service lines or adding lines at critical locations – would have enabled remediation to occur more quickly, especially in a single-flowline system.

Similarly, the method could be used with modification to remediate blockages in other well designs and for dissimilar production streams.

For example, in a well designed with perforation sleeves, the sleeves could be closed to isolate reservoir pressure from the well, providing a larger gas volume for pressure bleed-down and allowing significantly more volume into which flowline pressure could expand. In a well with a lower gas-to-liquid ratio and higher bubble point, the greater fluid volume exposed to the pressure reduction, once below the bubble point, would generate more gas volume to be bled down.

As tie-back lengths increase and their undulations across the seafloor become more dynamic, it will be beneficial to consider modifying subsea system designs to include spare chemical treatment and service lines at the wellhead and possibly at other critical points in the flowline.

If consulted early in the project development process, chemical treating experts with significant flow-assurance experience and an engineering background can recommend alternative subsea-system designs for a given application, based upon the expected composition of produced fluids.

In many cases the additional capital cost of adding chemical treatment lines and service lines at critical locations to prepare in advance for an inevitable flowline plug could result in significant cost savings, compared to the cost of mobilizing a service vessel for coiled tubing or wireline intervention. OE

About the author
Jeremy Lee is a project engineer at Champion Technologies, where he has acquired considerable knowledge and expertise in flow assurance, corrosion management, scale inhibition, and other production chemistry. Lee has a strong technical background and six years of hands-on experience in field applications offshore. He is a graduate of Louisiana Tech University with a BSc in chemical engineering.

Categories: Equipment Deepwater North America Flow Assurance

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