While great strides have been made in the advancement of low dosage hydrate inhibitors (LDHIs), the ind-ustry is still reluctant to embrace this alternative flow assurance sol-ution. BP took a bold step when it designed the Mungo satellite platform in the UK North Sea to operate with LDHIs rather than the traditional thermodynamic injection system.
While the LDHIs represent proven technology, this choice was integrated into the system's topside design to save the space and weight required to support a thermodynamic system.
Jim Blacklaws, BP Integrity team leader in the Central North Sea, said the economics of the Mungo field could not support a conventional flow assurance program. Mungo is one of several satellite fields tied back to the ETAP production platform. The Mungo wet gas production flows through a 22.6 km, 8-in. line. The unique composition of the Mungo production would require large quantities of glycol be injected in the line to prevent hydrate formation. This was not an option for BP because of both the cost of such a glycol injection program and the downstream consequences of introducing large amounts of this chemical into the export system.
Hydrate inhibitors are used to manage flow in lines that transport gas. Any time water is present in the line and it is traveling under pressure, there is a possibility of hydrate formation.
If the combination of pressure and temperature drive the production into a "super cooled" state, ice crystals form, then agglomerate to create a plug. The crystals may also bond with the inner wall of the flowline obstructing flow. Hydrate formation is a function of temperature and pressure so that there is a hydrate region for any given flow composition. Typically hydrates can form in pressures above 200 psi and temperatures below 60-75° F. Once a plug forms, Blacklaws said the line must be shut in and the plug allowed to melt. In the case of the Mungo flowline, this process took almost two weeks, at a cost of $15 million. This points out the critical role flow assurance plays in a production scenario.
The goal of hydrate management is to extend the range of pressure and temperature combinations where flow can be maintained. There are basically three types of chemical hydrate inhibitors: thermodynamic, anti-agglomerate, and kinetic. By far the most popular method of avoiding hydrates is thermodynamic inhibitors. This typically involves injecting large volumes of glycol into the flow. These volumes can run as high as 150% of the original flow rate.
While effective, there are a number of drawbacks to this method. It is labor-intensive, requiring workers on the platform to introduce the chemicals into the flow on a regular basis. The storage and pumping of the methanol also takes up valuable topside space and contributes to the weight of the platform. Transporting large quantities of these chemicals can be expensive, and there are penalties for production that reaches refineries containing too much glycol.
To reduce the trouble and expense of thermodynamic inhibitors, operators, working with service companies, have developed LDHIs. LDHIs are chemicals that help operators manage flow without the huge volumes of chemicals required for thermodynamic inhibition. Even so, the term "low dosage" is relative because these chemicals can make up a full 1% of the flow. Also, these chemicals are often used in concert with a thermodynamic inhibitor program. This lowers the requirements for glycol injection, but does not eliminate it.
The two types of LDHIs are anti-agglomerates and kinetic inhibitors. Anti-agglomerates allow ice crystals to form, but not agglomerate, or collect, into larger clusters. In this way, flow continues moving, as slurry, over long distances in very cold temperatures.
The kinetic inhibitors, also called threshold hydrate inhibitors (THIs) extend the induction time in the flowline, meaning they put off the formation of hydrates. This gives the production time to flow from the wellhead to the platform. These chemicals are effective, but not designed for long-distance transportation in deepwater or high-pressure applications where the super cooling is extreme.
If a flow is not in deepwater or traveling a long distance the less-expensive THI option is generally preferred.
While the LDHIs cost more up front, they eliminate the need for additional topside equipment and the space used to store large amounts of thermodynamic inhibitors. Still some operators remain skeptical. There is a lot of reluctance on their part to commit to something new. If a production platform is designed for an LDHI solution, it would require substantial renovation to switch over to a thermodynamic solution.
When one considers the number of high-volume, deepwater fields coming onstream, there are huge economic drivers behind alternative flow assurance solutions. Not only is it expensive and troublesome to transport large volumes of glycol to these remote facilities, but there are serious issues with how the glycol is handled downstream.
Operators are often assessed fines if there is too much glycol in their production. Beyond that, some of the giant deepwater fields will have production rates so high that it is simply impractical to try and treat them with glycol.
"There are places where they will not be able to pump enough (glycol)," said Ondeo Nalco Product Manager Steve Neff.
The super majors recognize this as a potential limitation and are working with the chemical companies, such as Ondeo Nalco, to develop LDHI solutions for major projects. This not only builds a track record of experience for these solutions, but also goes a long way toward driving the cost down. These, according to Neff, are the two biggest roadblocks to rapid implementation.
Thermodynamic inhibitors are bulky and cumbersome, they have downstream consequences, but they are tried and true solutions everyone uses. In an industry that is slow to change and hesitant to embrace new ideas, there is a strong comfort level associated with thermodynamic inhibitors.
"A lot of the operators are still a bit reluctant (to try LDHIs)," Neff said.
Recognizing the advantages of LDHIs, BP has put a lot of research into their application. "BP is by far the most aggressive operator out there in trying to prove these products," Neff said. Last year BP took the major step of implementing an LDHI flow management program on the Mungo field, in the UK North Sea. Initially, Mungo used a combination of LDHIs and glycol to ensure flow. This worked, but the occasional hydrate plugs still reduced throughput on the main pipeline. This solution also meant the operator still had glycol issues downstream. Blacklaws called the Mungo production one of the most difficult flow management applications around. The composition of the flow was such that it required a unique chemical solution.
Analyzing the composition of the flow, Nalco designed a THI that could eliminate the need for glycol injection while maintaining flow. Neff said the key to such a design is two fold. First, it is critical that the company understand the composition of the flow before selecting an inhibitor. Second, the chemical composition of the inhibitor shipped to the platform must be consistent. Using the oil and synthetic brine, Neff said, Ondeo tested its products, then had independent labs perform their own tests to ensure the results were valid.
Once the company was confident it had the proper chemicals, it waited for a planned shut-in to implement the new program. During the shut-in, the lines were blown down to melt all the hydrates inside, then the lines were purged with methanol to clear out any remaining ices.
When production came back online, glycol was used along with the THI. This was an insurance policy of sorts during the transition period. Over the next six months, the amount of glycol injected was reduced and the lines were regularly pigged. Pigging was previously not possible because of the hydrate build-up in the lines. Neff said the success on Mungo proves the potential of LDHI applications. This was by far the largest commercial application of the technology, he said, although kinetic inhibitors have been around for more than half a decade.
Although some operators are slow to come around, Neff said they all want the service company to be prepared. The challenge is to have the best possible LDHI solutions available, so if an operator agrees to apply the technology, they will have a successful experience.
There is still an issue of cost associated with these solutions. Part of the cost is the fact that LDHIs are not widely applied. Still, over the life of a field, there will be cost advantages in many cases. Blacklaws said Mungo was a unique case in that a special chemical solution was needed. He said an identical application may not crop up anytime soon, but he has no doubt that the more challenging reservoir conditions being encountered in new fields will bring flow assurance issues to the forefront.
"Hydrate control is becoming a key issue," he said.
Neff agrees that LDHIs are not suitable for every application. These are specialized solutions for cases where thermodynamic inhibitors are not practical. While most fields will continue to use glycol or methanol as inhibitors, there will be a whole generation of large deepwater fields that must find an alternative.
"It's just a matter of finding the right field for the application," Neff said.