Producing new fields with subsea trees and tieback of these new fields to existing platforms offers operators cost savings over new platform installation. One of the problems facing these tiebacks is the development of liquid slugs, either in the flowline or at the base of the riser.
These slugs often overwhelm the first stage separation system on the host platform, interrupting production. Shell Global Solutions has developed a system (now licensed by Dril-Quip) to eliminate this problem and stabilize the flow. This improves process operation, decreases start up times for production, and increases the average production volume.
When production moves from the subsea tree, down the flowline to a host platform, it is transported as a multiphase flow containing water, liquid hydrocarbons, and gas. Most flowlines carry production several miles to a platform or production facility in shallow water. These lines move over the seafloor where there are dips and low points. Liquids may settle in these low points, especially during shutdown.
As the flow moves, this collection of liquids can grow so that it fills the internal diameter (ID) of the flowline over a certain area. As the slug of fluid moves through the line, two things occur:
- The liquids push forward, collecting more liquid, and broadening the slug
- Gas builds up behind the slug unable to get around it.
As production moves up the continental shelf, gravity draws the liquids down, exacerbating this effect. By the time this flow reaches the host platform, the liquid slug or section of flow that is all liquid, can be up to a mile long. This is called a transient slug because it develops gradually as production travels along the flowline.
A number of factors affect how big these slugs are and how often they develop, but slower flow rates or interruption in flow can encourage their development.
Even a stratified flow with liquids on the bottom and gas on the top can run into trouble as it reaches the host platform. At the base of the platform where the flowline ties into the riser, there is an angle or elbow moving the horizontal flowline to vertical so it will run up the side of the jacket or platform to the topsides processing equipment.
This transition leads to liquids collecting out of the flow and pooling at the base of the riser. This slug continues to grow until the gas behind it has built up sufficient pressure to push the liquids up the riser. This type of slug flow is called severe slugging. It is characterized by long periods of production starvation followed by large liquid and gas surges.
Space and weight on offshore platforms are very limited. When a separation system and processing equipment are designed, they are built large enough to handle the anticipated production with a little excess capacity. The production equipment is tailored to the production mix the fields produce. These systems are adequate, but no larger than they have to be because of the premium on space and weight.
When a slug moves into the first stage separation equipment it has two negative affects on the equipment.
- The separator quickly fills with liquids triggering an alarm and alerting the crew that the liquids are about to flood the vessel. The liquids have to either be choked back at this point or drained off.
- Once the liquids pass through the separator there is a surge of gas. This overwhelms the compression equipment and causes gas to flare, or even causes high suction pressure shutdown at the compressors.
This cycle of slugging can occur more than once an hour. During production startup, when the liquids and gas first start to move, these liquid slugs and gas surges may result in a large production deferment. During normal operation, such interruptions in production are very inefficient and do not make for optimum use of the processing equipment. In addition, overall production is reduced because of the need to choke the flow and shut in production to handle these massive amounts of liquids and gas.
As more existing platforms are being used as hubs to tieback new fields, the processing equipment is relied upon to handle a flow rate different than what it was designed for, or to handle flows from more than one pipeline.
While these slugs can be minimized by slowing production rates, operators are looking at alternatives that would allow for maximum production rates without the interruption of slugs. Jim Kubasta, Project Manager with Dril-Quip said there are two approaches currently being used.
- Injecting gas at the base of the riser: This provides artificial lift for the liquids, moving them steadily through the system. This can alleviate the problem of severe slugging, but does not help with transient slugging in which the liquid column is already formed before it reaches the riser base.
- The intelligent choke: This is a system that opens and closes chokes to increase or reduce production flow, Kubasta said, deebased on the levels of liquids in the primary separator vessel. While this can keep liquids from overwhelming the system, it does not help with the gas surge or maintain optimum flow rates.
As production moves into deeper water flowlines will become longer, IDs will become larger, and the potential for slugs will increase. Anticipating this problem, Gert Haandrikman, multiphase flow team member with Shell Global Solutions said his company started work in the early 1990s on a system to control surges.
At the time, some fields in the North Sea were expected to reach a stage of maturity where they would produce under lower pressures with less gas and more water. This added to the surge problems. What Shell Global Solutions came up with is a system to monitor and adjust the flow of gas and liquids to the primary separator from the riser.
This Slug Suppression System, or S3 as it is called, takes liquid and gas production into a mini-separator that accepts flow from the riser before it reaches the primary separator. Sensors monitor the pressure and liquid level in the mini-separator, as well as the gas and liquid flow rates and feed this information to a computer.
Based on a continuously adapted optimum flow rate and mix, the control software activates valves that can open or close fast, compared to those of the first stage separator.
By monitoring the pressure and liquid levels in the mini-separator, the control unit can determine when liquids are gathering at the base of the riser. Once it senses this, the system opens the valve regulating gas flow. The drop in pressure draws the liquids up the riser, averting the slug.
With a transient slug, there is no way to preempt slug development. The goal of the system is to move the fluids through quickly, by bleeding off the gas pressure in front of it. The liquids are then moved into the main separator tank at a speed such that they do not flood the tank.
As the fluid level decreases, the system knows a gas surge is coming. Once the fluid is moved through the mini-separator, the gas behind it is contained and the pressure bled off gradually into the main separator. The object is to anticipate the changes in flow composition and compensate by opening and closing these valves.
By bleeding the compressed gas from the mini-separator to the main separator slowly, the system avoids overwhelming the processing equipment and minimizes the disturbances in the flowline. In a sense, the mini-separator handles the surges and lulls in flow, to dampen variations in production levels going to the primary separator for the transient slugs and prevent the formation of a slug at the riser base.
By eliminating the problem of severe slugs and compensating for transient slugs, the S3 system is able to provide reduced start-up times because the surges associated with startup are minimized. Once the production stream is online, the S3 controls production by eliminating peaks and valleys caused by surges that overwhelm equipment and which would otherwise cause interruptions in production. Overall, this results in greater production volumes. Later in the life of a field, as more fluids are produced and pressures are lower, the S3 can optimize this production as well.
The maximum liquid output of the system is specified by the software based on the size of the primary separator, Haandrikman said. This is helpful later in the life of the platform when it might be handling production from a different field or very different production from the same field after the field matures.
The S3 can be installed onto platforms already in service, according to Larry Reimert Dril-Quip's Co-Chairman. It is designed to use a spool piece between the riser termination and the primary separator. This spool piece installation can be accomplished during a routine shutdown.