One of the long-standing challenges to extended subsea tiebacks, especially in deepwater, is flow assurance. Cold temperatures over long distances cool the flow of oil and gas, causing wax build-up and, in the case of uncontrolled shutdowns, enabling conditions for hydrates to form inside the lines.
The formation of wax on the walls of the pipeline restricts, and in extreme cases, blocks production flow. Restrictions can be treated chemically, with inhibitors, or mechanically, by pigging. In a case where full blockage of the line occurs, circulation stops, meaning there is no way to move the pig through the line or apply a chemical treatment at the point of the blockage. When this happens, the pipeline is shut in, and traditionally the only two choices have been to install a new pipeline to reinstate production or to do nothing. In both of these cases, a blocked line remains on the seabed awaiting decommissioning.
The line replacement option is a time-consuming and costly procedure that results in lost production for several months. There are also environmental considerations, as the flowline remains full of hydrocarbons, and over time the pipeline will corrode, releasing the flowline contents into the sea.
In less extreme cases, chemical inhibitors can control wax build-up in oil lines and prevent hydrates from forming in wet gas lines, but even with chemical treatments, wax or hydrates can form on the flowline walls, restricting flow. This may not cause the pipeline to shut down, but it reduces the capacity of the line and, over time, can cost the operator money.
Halliburton's coiled tubing-based GoFlo unit offers chemical, mechanical, and thermal solutions for flow assurance problems offshore.
An additional flow assurance risk is that the composition of the produced fluids flowing through the line may change over time so that the treatment program initially designed for the well is no longer effective. In this case a new flow assurance program must be designed, but unfortunately, the first sign that this is needed is a restriction in flow.
There are a number of challenges associated with identifying and remediating flowline blockage. One basic challenge is to locate the problem area in the flowline. If the line is fully blocked, an operator can measure the volume of fluid in the line on one side of the plug and calculate how deep into the line the plug occurred. In a gas line, gamma radiation can be used to identify the difference in density between the gas and the hydrate plug. This method doesn't work in an oil line because the density of the fluid and plug are similar.
To mechanically service a line with restricted flow, a dual flowline must be in place. This allows a pipeline pig to run down one line and then return up the second. Such a design is standard on almost all fields, but there is an increased cost associated with installing two lines, as opposed to the one actually needed to flow production. A more complex challenge is to determine why the blockage occurred and design a system that will keep the line flowing freely. Another factor to consider is the flow of added inhibitor chemicals downstream. Refineries are increasingly sensitive to the amount of water they receive in their production stream.
To address a number of these issues, Halliburton Energy Services has developed a tool called GoFlo. Run off of a composite coiled tubing (CT) unit, GoFlo is a rapid response remediation tool, but according to Laurence Abney, GoFlo project manager for Halliburton, the system can be used as a flow assurance solution as well as a blockage remediation tool.
GoFlo can be run as far as 20 mi into a flowline. It is drawn down the line by a tractor developed by Welltec. The tractor has wheels made of metal that is softer than the flowline material that grip the flowline walls. This allows the tractor to draw the composite CT into the line without damaging the inside diameter surface. The light weight of the coiled tubing makes access much less difficult than it would be with conventional steel tubulars.
Once the tool reaches the restricted flow area, it uses either mechanical, chemical, or thermal techniques to remove wax build-up. The removed wax is then flowed back to the host facility. Abney said the tool has the ability to apply thermal energy to plugs, but this is typically avoided. If the plug can be mechanically removed at a cold temperature, then the wax is more likely to flow back to the host facility without clogging the system somewhere between the initial plug and the surface.
The idea behind GoFlo is to offer a portable solution that can either be skidded onto an existing offshore platform or run from a support vessel. The composite tubing not only allows the tool to be easily run into the flowline, but also means the CT unit will be lighter and more easily accommodated on a rig. Once the existing problem is addressed, GoFlo can further assist customers by evaluating what caused the problem. The goal is to avoid the need for future remediation by fine-tuning the flow assurance program. This would account for changes in flow composition.
With the system now available to the market, Abney said, a track record is being established that will lead to operators building this system into their flow assurance program. Abney said this will save upfront costs in the design of deepwater flowline systems and potentially eliminate the need for looped flowline systems. It will also reduce the need for flow assurance chemicals and lighten topsides loads. Optimizing flow means the flowlines are kept relatively clear, allowing more production to move through the system.
Active involvement with projects at the design stage enables the required access facilities to be designed and later incorporated during construction. The incorporation of facilities that allow for an intrusive blockage remediation system would give operators an advantage in their flow assurance strategies. Even with chemical prevention programs, Halliburton Integrated Technology Manager Colin Head-worth said hydrate blockage is a big problem for deepwater fields. Being involved in the front-end design allows for GoFlo techniques to be incorporated in a project's remediation strategy, potentially resulting in reduced chemical treatment programs and capex savings.
Such a system would dramatically reduce the need for methanol injection. Large volumes of methanol are currently the solution of choice for deepwater gas fields. These levels can be as high as a barrel of methanol for each barrel of water that flows through the line. There are a variety of advantages to lowering the amount of methanol required for injection. This saves the operator on the cost of the chemicals, as wells as the logistics of moving them offshore, and the weight and facilities that are used to store such volumes.
There are also maintenance and supply line issues, Headworth said. Reducing the amount of chemical inhibitors required eliminates the need for pigging and the infrastructure associated with this process. By eliminating shut-ins, Halliburton hopes the GoFlo system will enhance production over the field life. Abney said the company is currently working with operators on facilities designs that will take advantage of the GoFlo technology. It is a major commitment to design a system without a pigging loop, but he said he is confident GoFlo will find a broad range of deepwater applications.