Assuring pipeline flow with the total system in mind

Effectively managing flow assurance in subsea pipelines has far-reaching implications for the efficient operation of the entire asset. Given the complexity of subsea production systems, treating each potential flow assurance threat in isolation can lead to unforeseen problems. Baker Hughes uses what it calls its TOTAL SYSTEMS APPROACH process to consider fluid conditions downhole, change phase stability in the pipeline, and determine the impact any pipeline process will have on the surface processing equipment downstream (Figure 1).

True process optimization can only be achieved by taking a holistic view of the entire production system. A robust flow assurance program for pipelines is one that considers any and all flow threats throughout the entire system. The ultimate goal is to anticipate and mitigate any flow assurance risks before they become problems requiring expensive, technically challenging, and time-consuming remediation measures.

FIGURE 1. Produced fluids experience a wide range of conditions while moving from the reservoir to the sale point for a representative well. In this example, the pipeline system between the wellhead and the processing equipment is exposed to several flow assurance risks that include hydrates, waxes, emulsions, asphaltenes, scale, and corrosion. (Images courtesy of Baker Hughes)

The following sections will highlight some of the design and production flow characteristics one must consider when developing and implementing a full-systems flow assurance approach for pipelines. For the purposes of this example, it is assumed that all the hardware decisions (e.g., levels of insulation) have already been made. What remains are choices of operating procedures and chemical injection programs.

Begin at the source

The type of produced fluid coming out of the reservoir ultimately dictates the flow assurance risks. Thus, designing a flow assurance strategy should always begin with characterization of the produced fluids, which may include rates of oil, gas, and brine production; the producing gas-to-oil ratio (GOR); the mole fractions of C7+ and C20+ components; wax appearance temperature; asphaltene content; and brine analysis, to name a few.

It also is important to understand how the produced fluids – both hydrocarbon and brine – react to changes in temperatures and pressures as they make their way from the reservoir to the surface facility. This is achieved through laboratory tests and computer simulations that employ equation-of-state algorithms to arrive at a temperature/pressure (T-P) diagram for the system and estimate the risk of flow assurance issues. Figure 2 provides an example of such a T-P diagram. Figure 1 shows an overlay of flow assurance risks on the segments of the production system.

The role of subsea architecture

By the time the reservoir fluid reaches the wellhead at the seafloor (mudline), it has lost heat to its surroundings. At the seafloor, each piece of equipment is surrounded by seawater just a few degrees above freezing. The drop in pressure and temperature and the corresponding flow assurance risks that arise are understandable when considering the general layout of the seafloor equipment and facilities. Wellhead equipment, chokes, equipment connection lines, manifolds, and control equipment all play a role in flow assurance.

The subsea tree contains a choke or control valve that modulates the flow rate by restricting the cross-sectional area of the flow. Turbulence created at the choke adds another pressure-loss point in the flow path of a liquid, which ultimately is dissipated as thermal energy into the surroundings. This is the most likely location in the flow system for emulsions to be created.

FIGURE 2. A T-P diagram for a black oil with a density of 26° API and a GOR of 14 cm/stock tank barrel (500 cf/stock tank barrel). In moving from the reservoir to the surface facility during normal production, the pressure and temperature decrease, and in the pipeline section (between the choke and the surface facilities), there is a likelihood for hydrates and wax formation as well as a risk of asphaltenes.

Production then moves to the subsea manifold, where flow from several wells is typically blended into a single flowline. In addition, fluids may be brought from other fields by means of a tieback to increase equipment use or reduce development costs. All this fluid commingling creates many opportunities for solid phases to form. Therefore, it is important to know the proportions of fluids from different wells and the composition of the fluids.

Setting off across the seafloor for a distance of several miles, the flowline then carries the commingled fluids from several wells to the surface facilities. In terms of retention time, fluid spends more time in the flowline than any other part of the flow path except for the reservoir. The flowline, and the produced fluids it transports, experience a continuous pressure drop during the trip from the seafloor to sea level.

In the example in Figure 2, the produced fluids drop below the wax appearance temperature of 10°C (50°F) in the flowline during normal operating conditions. The pressure approaches the bubble point on the phase envelope as the fluid nears the riser, suggesting the potential risk of asphaltenes.

The potential for hydrate formation also is high under the conditions in the subsea flowline when the temperature drops below 21°C (70°F). As noted in Figure 1, the models also predict a risk of scale and corrosion beginning in the wellbore and continuing into the flowline.

Detailed laboratory evaluation should be carried out to select the best suite of chemical inhibitors to mitigate the aforementioned risks. A key success factor is ensuring the mutual performance compatibility of these chemicals as well as their compatibility with the injection system and impact on fluid separation downstream.

Furthermore, the range of operating scenarios should be considered; it is particularly important to consider the impact of a shut-in and subsequent restart on the risk of hydrate blockages. Detailed plans should be developed for maintenance shutdown to ensure that restart is possible.

Prevention vs. reaction

A sound, full-systems approach to flow assurance should provide a proactive means of managing production and preventing flow slowdowns or stoppages.
The mitigation strategy should include the right combination of treatment chemistries – hydrate inhibitors, scale and asphaltene inhibitors, emulsion breakers, and corrosion inhibitors – that are introduced as part of an ongoing flow assurance program. And because fluid rates, compositions, and reservoir conditions change dramatically during the life of a well, the treatment program also should include a comprehensive monitoring scheme to assess changing flow assurance threats.

Such a comprehensive and preventative strategy can detect a reduction in flow capacity at 10%, when it can be more quickly and efficiently addressed. Waiting until flow capacity has dropped to 50% or more is often too late to avoid the cost, time, safety risk, and complication of a more involved mitigation solution.

Ultimately, a full-systems approach to flow assurance proves the old saying that “an ounce of prevention is worth a pound of cure.”

The authors wish to thank Russ Fisher for his significant contributions to this article.