As a wider variety of deepwater solutions are brought on line to address an increas- ingly diverse collection of projects, flow assurance has emerged as a major consideration. While historically opera-tors have strived to avoid flow assurance prob-lems, there is a growing argument for simply managing such problems as they arise. This can create substantial savings on the capital expense side, which must be weighed against the possible impact on operating costs and uptime.
What has always been an issue in offshore fields has taken on an increased importance in deepwater developments. Flow assurance problems, primarily hydrate and paraffin formation, are exacerbated by several factors unique to the deepwater environment, according to Robert Helmkamp, subsea systems engineering manager for Shell International E&P Inc. (SIEP). In deepwater, the temperatures are lower (near freezing), the pressures higher, and the costs associated with a flow assurance problem also increase.
With its large portfolio of deepwater prospects, Shell has made a push to better understand the drivers behind flow assurance problems. The goal is to evaluate existing solutions in terms of future projects. In many cases, existing solutions can be modified to address flow assurance concerns on a new field. But in some cases, research supports developing new technology or techniques. Helmkamp said his company has good fluid, hydraulic, and thermal analysis capabilities that are useful in evaluating what type or level of flow assurance challenges will exist in a field. This is weighed against the capital cost of avoiding these problems. This type of risk management helps a team establish its flow assurance strategy, placing it in the context of a life-cycle value analysis. It also helps the team explain its recommendations to the leaders who must approve such projects.
In broad strokes, Helmkamp explained that there are standard methods to manage flow assurance problems in oil and gas flowlines. To inhibit the formation of hydrates and paraffins in oil flowlines, operators insulate the deepwater flowlines against the low seabed temperatures. To protect gas flowlines, the continuous injection of chemical inhibitors is generally the approach taken. While these are the typical solutions that come to mind, Helmkamp said they do not fit in all cases, including some of the more extreme environments being encountered in deepwater. These are also not foolproof, requiring back-up solutions for remediation of plugs that may form due to unplanned operational events.
Typically, when a hydrate plug forms in a gas or oil line, it must be melted before flow can resume. Pigging is no good in this situation because the plug makes it impossible to move the pig through the line. To melt the plug, the line is pressured down, preferably on both ends. For a subsea well, this means pressuring down at the production platform, but possibly also near the wellhead using a rig or other intervention vessel. This process can be expensive because of the need for the intervention vessel and the loss of production while waiting for an intervention vessel to become available, and then for the plug to melt. Helmkamp said the same insulation technology that protects the flow inside the line from the cold seabed temperatures works in reverse when trying to melt a plug. It can take months for plugs to dissolve on their own.
In case of an unplanned shutdown of an oil flowline, depressuring the line typically prevents hydrate plugs. This is a simple procedure in a line flowing uphill to a host, since the gas rises in the line and gathers in the risers. However, in more deepwater developments, individual fields are tied back to a large host called a hub. Hubs draw from fields both deeper and shallower than themselves, so some of the satellite fields can have flowlines that travel downhill. In these situations, it is difficult to get the gas-charged "live" oil out of the line by depressuring, so "dead" oil may be circulated to remove the live oil to keep hydrate plugs from forming. When host facility power outages or other unexpected problems occur, preventing "dead" oil circulation, flowlines are at risk for forming hydrate plugs.
Many hub facilities will be accepting produc-tion from a variety of fields, said Kent Stingl, Subsea & Pipeline project team leader for SIEP. Production composition varies, as do flowline and riser configurations. When the additional variable of up-dip or down-dip production returns is taken into account, it is clear custom flow assurance solutions will be required.
"We're moving into a different field layout situation for many of these unique fields," Stingl said.
Another consideration on longer tiebacks is the hub's ability to support a flowline blockage remediation project.
Shell has developed electrical heating solutions for flowlines to add to it flow assurance options. One such solution, called ever-ready electrical heating, runs the full length of the flowline. This system is powered and controlled onboard the hub facility so the operator can activate the heating system and remediate a problem at any time. Helmkamp said it was installed on the Serrano and Oregano fields as a solution for cold start-ups for these fields with single flowlines. Helmkamp said these decisions are carefully made in terms of risk management. The technology itself is interesting to develop and put into the field, but it must make economic sense and add value to the project.
The second design is called electric heating ready. This system is less expensive to install, but is not as easy or inexpensive to activate and covers only a specific portion of a flowline. In the center of this line would be an integral mid-line electrical connector section that is wired for electrical heating. In a situation where blockage occurs, a dive support vessel (DSV) would be dispatched to the scene.
The DSV would lower a subsea transformer, using a power umbilical, to the seabed near the affected length of flowline and then launch an ROV to install the electrical leads in the integral mid-line connector. Using power generated at the surface on the DSV, the ROV would hook up the section of pipe-in-pipe flowline, which would use the power to heat the line and dissolve the plug. Because this second solution requires intervention by a DSV, it is more expensive to activate than a solution that is wired back to the hub. But the savings up front means that if remediation is not often needed, this solution is more economic.
The wired solution is also a useful option for development scenarios where several smaller fields tie into a main flowline daisy-chain fashion. This allows the system designer to pinpoint potential problem areas and pre-wire them for remediation.
No single flow assurance solution is the best in every case. The more options an operator has, the better chance there is of making a particular project viable. With the many challenges of deepwa-ter, it will take a combination of flow assurance management and remediation techniques to ensure fields of different sizes and in different loc-ations can be brought on line and kept in prod-uction. This dependability allows for develop- ments in extreme subsea environments.