The troublesome hydrocarbon and water compounds
spotlight: FloW AssURANCE
Breaking the ice The troublesome hydrocarbon and water compounds known as hydrates can congest flowlines, slowing or completely halting the flow of fluids. Jennifer Pallanich talks to a subsea contractor well versed in the ways of ice and how to thaw it.
H
ydrate problems occur when conditions depart from the operating parameters for the system, says Chris Mancini, senior project manager with Oceaneering in Houston. “In almost every case that we’ve found, it’s because there has been some sort of departure from the designed operating limits of the facility,” such as a switch flipped, or a shut-in that did not follow the entire flow assurance steps, he adds. “If you operate with the system as it’s intended, you are not going to have a problem. It’s outside those parameters.” Oceaneering gets the call when those parameters are exceeded. “We’re like the paramedics arriving on the scene. The accident’s already occurred. So we do triage on the system,” says Mancini, a mechanical engineer. Having received a call from an operator, step one for the Oceaneering team is locating the flowline blockage, often using non-invasive methods such of gamma ray densitometry or pressurising the system to determine pressure versus volume response. Then it is 62
a case of working out how to resolve the problem and arranging the necessary vessels, ROVs, subsea hardware, chemicals, and remediation skids. Determining the composition of the blockage is another piece of the puzzle. “More often than not, when they do run into a blockage, operators automatically assume it’s a hydrate. We’ve found it’s never just a hydrate. There’s always
UPSTREAM TECHNOLOGY 01 | 2014
a collateral issue,” Mancini says, citing asphaltenes, paraffins, pigs or other stubborn obstructions among the host of potential collateral problems they have to be prepared for. “Hydrates are pretty easy to solve — it’s the other collateral that’s more difficult to resolve.” Applying heat, depressurising the system or injecting chemicals can halt hydrates in their tracks. Any one of those three things is going to resolve
the hydrate. Hydrates can’t exist under certain circumstances,” Mancini says. “Under 150 psi, a hydrate will decompose. It must. It’s physics. It’s the law.” Collateral issues can often prove more troublesome. By way of example, Mancini points to a 2012 project in the Gulf of Mexico that required his company to deal with a suspected hydrate in a 42-kilometre stretch of six inch flowline in 1525 metres
SEABED S ETTING: R OV manip Remediati ulator arm on Skid at and Hydra work durin operations. te g blocked pipeline
of water. “We went down and quickly discovered there was no hydrate at all. It was loaded with polymers,” he recalls. The polymers resulted from “an unanticipated interaction between corrosion and paraffin inhibitors”. Electrical engineer Hans Kros, Oceaneering’s oilfield project group manager for inspection, maintenance and repair, explains that the liner had become delaminated, ultimately
collapsing inside the pipeline and forming “several large wads”. Chemicals other than the planned methanol had to be introduced to clear the polymer blockage. “Methanol wasn’t going to resolve it because that’s for hydrates,” Mancini explains. The project team reconfigured the Oceaneering Flowline Remediation System (FRS) to accommodate the “potent solvent” needed for this job, then
Images: O ceaneering
spotlight: FloW AssURANCE
LARGE VOLUME: Deployed by multi-service vessels and operable to 3000 metre water depths, the Flowline Remediation System is for large-volume lines and requires 6 metres x 4.6 metres of deck space.
contingency” in case asphaltenes happen to be a secondary obstacle, Mancini notes. He says having that contingency plan ready to roll is Oceaneering’s modus operandi for blockages, although clients do not always sign onto those plans. “Most subsea facilities have been designed to prevent the formation of blockages, but over the past five or six years the operators have begun to incorporate facilities to remediate,” Mancini points out. “Now it’s prevention plus access points and chemical points, so it’s easier to resolve.” These bespoke plans, he says, make remediation faster and safer.
used depressurisation along with chemical injection and nitrogen injection to resolve the blockage, transport the polymers out of the flowline, and re-establish flow. In another exercise last December, the company was preparing for an international hydrate remediation project for a flowline in 1400 metres water depth. “While the operator believes it’s a hydrate, we have convinced them to have the other chemicals available as a
The everyday hydrate Hydrates also form in locations other than flowlines. Mancini refers to these as “everyday or smaller hydrates. Everyday hydrates are associated with everyday long-term pressure caps on manifolds or tree caps or control lines for subsea safety valves… They are normally encountered during routine operations and are almost expected.” They are so common, he
UPSTREAM TECHNOLOGY 01 | 2014
63
»
spotlight: FloW AssURANCE
“Hydrates are pretty easy to resolve — it’s the other collateral that’s more difficult.” Chris Mancini, Oceaneering
CRAB COOKER: Oceaneering’s Pipeline Heating Skid, capable of providing water up to 110°C, ready to ship.
» adds, that hydrates are present
around 90% of the time when an operator removes a cap from a manifold or a tree. “Gas migrates to the small, dead volumes over the years to form some pretty nasty hydrates, and they sometimes interfere with the ability to pull those [caps] off,” Mancini reports. Oceaneering employs a small Hydrate Remediation Skid to address these so-called everyday hydrate situations. These ROVdeployable skids have most of the same capabilities as their larger brethren, but on a smaller scale, Kros notes. The belly-mounted skid has pumps for injecting inhibitor chemicals and a means of depressurising the hydrate to force it to decompose. Local heat In late 2012, an operator commissioned Oceaneering to design a tool that would interface with an ROV but be powered from the topsides to apply heated seawater to a six inch export line. Over the course of five months, the company developed and tested a tool that is deployed via the same style of cage used to overboard a typical work-class ROV, reports engineering lead Kosta Papasideris. This cage serves as the power and deployment host to the Pipeline Heating Skid (PHS), which features a pair of powerful heating elements. “The tool was designed around the largest, most powerful heat production that was allowable
SMALL VOLUME: Neutrally buoyant in seawater and weighing 700 kilograms in air, the ROV-deployed and operated Hydrate Remediation Skid measures 2.1 metres x 1.5 metres x 0.6 metres and can depressurise small volume production piping.
from our topside electric supply,” Papasideris says, noting it can put out a maximum of 153 kilowatts as the initial specs requested as much power as possible be supplied from the topsides. “Safety was a tremendous priority because of the high power topside.” On international deployment, the PHS was seated onto the six inch pipe with a rubber insulating seal. “When heating operations are ready to commence, seawater is drawn into an onboard storage tank insulated from the ambient colder water,” Papasideris, an electrical engineer, explains. “That water inside the storage tank on the tool is heated via the heating elements, and circulated inside that volume until the operator engages a circulation pump which directs the newly heated water through a flow
64 UPSTREAM TECHNOLOGY 01 | 2014
cavity making contact with the pipe surface.” The heated water travels about three metres along the pipe’s surface and exits, then the process is repeated with fresh, cold seawater. Papasideris describes this tool as “a little unique” because there are no pre-existing or installed heating coils around the pipe. It was developed to apply the heat directly to the surface of the pipe to decompose what were thought to be hydrates blocking the export line. According to Mancini, the export line in 1400 metres of water had formed hydrates following damage to subsea infrastructure that had introduced water into the system. After depressurising the line failed to resolve the blockage, the customer decided there were likely other features in the export line causing the hydrates to remain problematic. The company had estimated that simply relying on heat transfer from the deepwater environment would take over three years for the hydrates to resolve themselves, Mancini says, so the operator chose to speed the process up through external heating. “Operators generally are concerned with plug mobilisation and overpressurisation due to decomposition within a confined volume,” he notes. “Because of these perceived
risks, very precise temperature and consequently power controls are incorporated into the tool.” Oceaneering set the heating elements on the PHS to operate at a range of 15°C to 18°C, with 20°C being the maximum temperature allowable. This temperature range was, Papasideris says, “just enough to start getting hydrate to decompose” over the five weeks the tool operated on the export line last summer. The design capability of the PHS to provide up to 110°C degree water might have given rise to the “crab cooker” nickname given to it by the project team. While the PHS performed as requested, there was “no indication of hydrates being decomposed during the campaign”, Mancini recalls. “The collateral issue was a pig that wasn’t anticipated.” Because of concerns associated with external heating, the tool is not expected to be deployed too often for that type of project, but Mancini believes it could be beneficial for external hydrates. “One of the concerns drillers have is that while drilling they could get hydrates forming in connectors that could preclude from unlatching.” The tool could, he says, provide a “limitless supply of heat” to resolve issues such as external hydrates on connectors, trees and other subsea infrastructure. “I think that’s a great application. They haven’t done it yet because they don’t know it’s possible,” Mancini concludes.
Breaking the ice The troublesome hydrocarbon and water compounds known as hydrates can congest flowlines, slowing or completely halting the flow of fluids. Jennifer Pallanich talks to a subsea contractor well versed in the ways of ice and how to thaw it.
H
ydrate problems occur when conditions depart from the operating parameters for the system, says Chris Mancini, senior project manager with Oceaneering in Houston. “In almost every case that we’ve found, it’s because there has been some sort of departure from the designed operating limits of the facility,” such as a switch flipped, or a shut-in that did not follow the entire flow assurance steps, he adds. “If you operate with the system as it’s intended, you are not going to have a problem. It’s outside those parameters.” Oceaneering gets the call when those parameters are exceeded. “We’re like the paramedics arriving on the scene. The accident’s already occurred. So we do triage on the system,” says Mancini, a mechanical engineer. Having received a call from an operator, step one for the Oceaneering team is locating the flowline blockage, often using non-invasive methods such of gamma ray densitometry or pressurising the system to determine pressure versus volume response. Then it is 62
a case of working out how to resolve the problem and arranging the necessary vessels, ROVs, subsea hardware, chemicals, and remediation skids. Determining the composition of the blockage is another piece of the puzzle. “More often than not, when they do run into a blockage, operators automatically assume it’s a hydrate. We’ve found it’s never just a hydrate. There’s always
UPSTREAM TECHNOLOGY 01 | 2014
a collateral issue,” Mancini says, citing asphaltenes, paraffins, pigs or other stubborn obstructions among the host of potential collateral problems they have to be prepared for. “Hydrates are pretty easy to solve — it’s the other collateral that’s more difficult to resolve.” Applying heat, depressurising the system or injecting chemicals can halt hydrates in their tracks. Any one of those three things is going to resolve
the hydrate. Hydrates can’t exist under certain circumstances,” Mancini says. “Under 150 psi, a hydrate will decompose. It must. It’s physics. It’s the law.” Collateral issues can often prove more troublesome. By way of example, Mancini points to a 2012 project in the Gulf of Mexico that required his company to deal with a suspected hydrate in a 42-kilometre stretch of six inch flowline in 1525 metres
SEABED S ETTING: R OV manip Remediati ulator arm on Skid at and Hydra work durin operations. te g blocked pipeline
of water. “We went down and quickly discovered there was no hydrate at all. It was loaded with polymers,” he recalls. The polymers resulted from “an unanticipated interaction between corrosion and paraffin inhibitors”. Electrical engineer Hans Kros, Oceaneering’s oilfield project group manager for inspection, maintenance and repair, explains that the liner had become delaminated, ultimately
collapsing inside the pipeline and forming “several large wads”. Chemicals other than the planned methanol had to be introduced to clear the polymer blockage. “Methanol wasn’t going to resolve it because that’s for hydrates,” Mancini explains. The project team reconfigured the Oceaneering Flowline Remediation System (FRS) to accommodate the “potent solvent” needed for this job, then
Images: O ceaneering
spotlight: FloW AssURANCE
LARGE VOLUME: Deployed by multi-service vessels and operable to 3000 metre water depths, the Flowline Remediation System is for large-volume lines and requires 6 metres x 4.6 metres of deck space.
contingency” in case asphaltenes happen to be a secondary obstacle, Mancini notes. He says having that contingency plan ready to roll is Oceaneering’s modus operandi for blockages, although clients do not always sign onto those plans. “Most subsea facilities have been designed to prevent the formation of blockages, but over the past five or six years the operators have begun to incorporate facilities to remediate,” Mancini points out. “Now it’s prevention plus access points and chemical points, so it’s easier to resolve.” These bespoke plans, he says, make remediation faster and safer.
used depressurisation along with chemical injection and nitrogen injection to resolve the blockage, transport the polymers out of the flowline, and re-establish flow. In another exercise last December, the company was preparing for an international hydrate remediation project for a flowline in 1400 metres water depth. “While the operator believes it’s a hydrate, we have convinced them to have the other chemicals available as a
The everyday hydrate Hydrates also form in locations other than flowlines. Mancini refers to these as “everyday or smaller hydrates. Everyday hydrates are associated with everyday long-term pressure caps on manifolds or tree caps or control lines for subsea safety valves… They are normally encountered during routine operations and are almost expected.” They are so common, he
UPSTREAM TECHNOLOGY 01 | 2014
63
»
spotlight: FloW AssURANCE
“Hydrates are pretty easy to resolve — it’s the other collateral that’s more difficult.” Chris Mancini, Oceaneering
CRAB COOKER: Oceaneering’s Pipeline Heating Skid, capable of providing water up to 110°C, ready to ship.
» adds, that hydrates are present
around 90% of the time when an operator removes a cap from a manifold or a tree. “Gas migrates to the small, dead volumes over the years to form some pretty nasty hydrates, and they sometimes interfere with the ability to pull those [caps] off,” Mancini reports. Oceaneering employs a small Hydrate Remediation Skid to address these so-called everyday hydrate situations. These ROVdeployable skids have most of the same capabilities as their larger brethren, but on a smaller scale, Kros notes. The belly-mounted skid has pumps for injecting inhibitor chemicals and a means of depressurising the hydrate to force it to decompose. Local heat In late 2012, an operator commissioned Oceaneering to design a tool that would interface with an ROV but be powered from the topsides to apply heated seawater to a six inch export line. Over the course of five months, the company developed and tested a tool that is deployed via the same style of cage used to overboard a typical work-class ROV, reports engineering lead Kosta Papasideris. This cage serves as the power and deployment host to the Pipeline Heating Skid (PHS), which features a pair of powerful heating elements. “The tool was designed around the largest, most powerful heat production that was allowable
SMALL VOLUME: Neutrally buoyant in seawater and weighing 700 kilograms in air, the ROV-deployed and operated Hydrate Remediation Skid measures 2.1 metres x 1.5 metres x 0.6 metres and can depressurise small volume production piping.
from our topside electric supply,” Papasideris says, noting it can put out a maximum of 153 kilowatts as the initial specs requested as much power as possible be supplied from the topsides. “Safety was a tremendous priority because of the high power topside.” On international deployment, the PHS was seated onto the six inch pipe with a rubber insulating seal. “When heating operations are ready to commence, seawater is drawn into an onboard storage tank insulated from the ambient colder water,” Papasideris, an electrical engineer, explains. “That water inside the storage tank on the tool is heated via the heating elements, and circulated inside that volume until the operator engages a circulation pump which directs the newly heated water through a flow
64 UPSTREAM TECHNOLOGY 01 | 2014
cavity making contact with the pipe surface.” The heated water travels about three metres along the pipe’s surface and exits, then the process is repeated with fresh, cold seawater. Papasideris describes this tool as “a little unique” because there are no pre-existing or installed heating coils around the pipe. It was developed to apply the heat directly to the surface of the pipe to decompose what were thought to be hydrates blocking the export line. According to Mancini, the export line in 1400 metres of water had formed hydrates following damage to subsea infrastructure that had introduced water into the system. After depressurising the line failed to resolve the blockage, the customer decided there were likely other features in the export line causing the hydrates to remain problematic. The company had estimated that simply relying on heat transfer from the deepwater environment would take over three years for the hydrates to resolve themselves, Mancini says, so the operator chose to speed the process up through external heating. “Operators generally are concerned with plug mobilisation and overpressurisation due to decomposition within a confined volume,” he notes. “Because of these perceived
risks, very precise temperature and consequently power controls are incorporated into the tool.” Oceaneering set the heating elements on the PHS to operate at a range of 15°C to 18°C, with 20°C being the maximum temperature allowable. This temperature range was, Papasideris says, “just enough to start getting hydrate to decompose” over the five weeks the tool operated on the export line last summer. The design capability of the PHS to provide up to 110°C degree water might have given rise to the “crab cooker” nickname given to it by the project team. While the PHS performed as requested, there was “no indication of hydrates being decomposed during the campaign”, Mancini recalls. “The collateral issue was a pig that wasn’t anticipated.” Because of concerns associated with external heating, the tool is not expected to be deployed too often for that type of project, but Mancini believes it could be beneficial for external hydrates. “One of the concerns drillers have is that while drilling they could get hydrates forming in connectors that could preclude from unlatching.” The tool could, he says, provide a “limitless supply of heat” to resolve issues such as external hydrates on connectors, trees and other subsea infrastructure. “I think that’s a great application. They haven’t done it yet because they don’t know it’s possible,” Mancini concludes.
