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In-Situ Applied Coatings for Mitigating Gas Hydrate Deposition in Deepwater Operations
Project Number
DE-FE0031578
Last Reviewed Dated
Goal

The overarching objectives for this project are to develop, investigate, and validate (for field and commercial deployment) robust pipeline treatments to prevent/minimize gas hydrate and other solid deposition in subsea oil flowlines. A robust pipeline treatment that is capable of preventing adhesion/deposition will be a major fundamental breakthrough in flow assurance science and engineering and to critical deepwater field operations. This project will address the current major outstanding issues of mitigating gas hydrate, wax and asphaltene deposition in different pipeline conditions, which have not been solved to date despite previous attempts/studies.

Performer(s)

Colorado School of Mines (CSM), Golden, CO 80401
Oceanit Laboratories, Inc., Honolulu, HI 96813

Background

Gas hydrates are considered the major flow assurance problem during Deepwater offshore production and transportation of oil and natural gas, which if not addressed adequately can present severe production, environmental, and safety issues during operation (Sloan and Koh, 2007). The high pressure (depths of seawater) and low temperature (on the seafloor) conditions in deepwater environments are ideal for providing thermodynamic stability of gas hydrates, thereby enabling gas hydrates to form and potentially plug flowlines during oil and gas production and transportation. The formation of flowline blockages due to gas hydrates may result in rupture of the flowline, gas and oil spill and leakage, and hence catastrophic safety, economic, and environmental consequences. Costs for gas hydrate mitigation can exceed $1M/mile of pipeline, plus $100M/year in chemical costs for complete gas hydrate avoidance.

The conventional method of gas hydrate avoidance using thermodynamic inhibition (THI), e.g. using methanol or glycol, is becoming increasingly unfeasible from both an economic and environmental standpoint, particularly with deepwater developments which present higher pressure conditions and hence more favorable conditions for gas hydrate stability, as well as maturing facilities in which the water content can increase significantly during the lifetime of the field. Thus, there is an imminent need for a new approach that allows operators to produce from wells where traditional gas hydrate mitigation is unfeasible. Low surface energy materials which can be applied in situ to operational pipelines represent a critical industry solution to gas hydrate mitigation, as these advanced treatments can repel gas hydrate adhesion to the wall, as well as repel the water layer that allows gas hydrates to form directly on the steel pipe surface. Initial testing indicated that gas hydrate adhesion could be decreased by over an order of magnitude, but larger-scale experiments to evaluate and advance coating performance and survivability needed to be performed to validate these preliminary results.

Similarly to hydrates, wax and asphaltene solid deposits can disrupt and defer production as they build-up on pipe surfaces. Treatments for these other flow assurance solids can vary, such as chemical dosing, mechanical removal, or thermal treatments. In some cases, these treatments can interact unfavorably if multiple depositing species are present. A treatment option that can address multiple flow assurance concerns offers a unique and disruptive step forward in reducing maintenance costs and mitigating severe economic and safety risks caused by these flow assurance solids.

Impact

As oil and gas production wells mature, the water content and oil composition can change and increase the risk of gas hydrate, wax, and asphaltene deposition and blockages in flowlines, with the cost of complete inhibition becoming prohibitive. The ability to mitigate flow assurance risks in maturing flowlines can extend the life of the field, significantly reduce operational costs from inhibitor injection and prevent potential safety hazards to personnel and equipment, and prevent potential environmental hazards. This research allows for a novel, cost-effective method of mitigating gas hydrate and other pipeline solids deposition/blockages in flowlines, extending the life of the field while being minimally disruptive to normal flowline operation. The omniphobic surface treatment developed in this work can significantly improve the economics of energy transport by providing flow assurance and limiting catastrophic blowouts.

Accomplishments (most recent listed first)
  • DOE-NETL Update Meetings held August 2021, June 2021, October 26, 2020, March 23, 2020, August 28, 2019, May 7, 2019, March 11, 2019, November 30, 2018.
  • Offshore Technology Conference, OTC 2022 (paper submitted), OTC 2021 (paper published), OTC 2020 (2 papers published), NACE Corrosion 2021 (paper submitted and presented). International Conference on Gas Hydrates, ICGH10 2020 (paper accepted), OTC 2019 (paper published), Thermophysical Properties, TPP 2021 (oral paper presented); SPE Journal 2021 (paper published), Fuel Journal 2021 (paper published).
  • Kickoff meeting with NETL held May 23, 2018.
Current Status

CSM has demonstrated through extensive testing for more than 2 years in their deposition loop system the hydrate-phobic properties of Oceanit’s pipeline surface treatment under both steady state and more stringent transient simulated field conditions. Hydrate deposition was mitigated/reduced significantly in treated pipes, compared to untreated pipes. The mechanism of the hydrate-phobic behavior of the surface treatment includes: delaying/inhibiting hydrate nucleation onset times, reducing hydrate crystal growth rates, and reducing surface-hydrate particle adhesion. Loop tests have been also performed to demonstrate the significant reduction in asphaltene deposition for treated corroded pipes, while bench scale testing has indicated that wax deposition may also be decreased on treated surfaces (see Figure 1).

Material development and testing have demonstrated that DragX™ has diverse chemical resistance and long-term survivability, longevity/durability under simulated field conditions of high pressure and wide temperature ranges that exceed the usual operating conditions of the field. Third party and Oceanit’s in-house wide range of ASTM testing (e.g., D3359, D6943-15 B, D6943-15 C) have provided the critical stability/durability data required by the industry to de-risk the field deployment of the DragX technology for flow assurance solids mitigation.

The results demonstate critical disruptive breakthroughs in deepwater pipeline surface treatment and deepwater flow assurance technologies. Specifically, the omniphobic treatment, which can be applied in situ to existing facilities, has been demonstrated to reduce and mitigate hydrate adhesion and deposition and delay hydrate nucleation, while simultaneously preventing corrosion and reducing wax and asphaltene deposition. Larger-scale extended and long-term tests under simulated field conditions have demonstrated hydrate deposition mitigation under steady state and stringent transient conditions (Figure 2). Similarly, longer-timescale loop testing for asphaltene deposition mitigation has been demonstrated (Figure 3), with loop tests for wax deposition mitigation (Figure 4) underway to further test and validate the robustness of the coating for a broad range of pipeline conditions. A new transient conceptual model has been developed to advance the critical understanding of gas hydrate deposition/plugging process mechanisms during the most severe conditions of shut-in/cold restart in the field (Figure 5). The extensive deposition flowloop test results under simulated field conditions have been instrumental to the development of this new mechanistic understanding, which can be used to improve models, design future experiments, and and inform industry decisions during operation.

Field test planning for deployment of this disruptive technology, along with application logistics and long-term material survivability, are currently underway, with field-scale model development and simulations performed to assess film growth/deposition mitigation in a surface-treated pipeline. Regular meetings with industry members in the form of consortium updates and in-depth discussions with interested parties are serving to direct the technology validation, such that it demonstrates the most important de-risking concepts for field implementation. This new technology would present a step-change for the industrial mitigation of major pipeline hazards for the industry. It is therefore important to select a field test site and test partner who can demonstrate the technology on an industrial scale, while minimizing risk.

DragX™ omniphobic coating creates a low surface energy layer adhered to the pipe, which decreases adhesion from depositing solids: hydrates, waxes, asphaltenes.
Figure 1: DragX™ omniphobic coating creates a low surface energy layer adhered to the pipe, which decreases adhesion from depositing solids: hydrates, waxes, asphaltenes.
Figure 2. Extensive long-term larger-scale deposition loop tests demonstrate DragX™ pipeline coating delays nucleation of hydrates, reduces hydrate growth and surface-hydrate adhesion, thereby mitigating deposition, and maintains a lower pressure drop by creating a smooth, low adhesion surface in treated pipe sections of the deposition loop. Note: testing has been performed for over a year, with the results shown here for repeated transient restart tests (8 untreated, which all led to plugging; 3 treated, which all continued to enable fluid transport).
Figure 2. Extensive long-term larger-scale deposition loop tests demonstrate DragX™ pipeline coating delays nucleation of hydrates, reduces hydrate growth and surface-hydrate adhesion, thereby mitigating deposition, and maintains a lower pressure drop by creating a smooth, low adhesion surface in treated pipe sections of the deposition loop. Note: testing has been performed for over a year, with the results shown here for repeated transient restart tests (8 untreated, which all led to plugging; 3 treated, which all continued to enable fluid transport).  
Figure 3. Deposition loop tests demonstrate the significant reduction in deposition of the mass of total solids and extracted asphaltenes for surface treated corroded pipe compared to the untreated corroded section (which more closely represent field conditions).
Figure 3. Deposition loop tests demonstrate the significant reduction in deposition of the mass of total solids and extracted asphaltenes for surface treated corroded pipe compared to the untreated corroded section (which more closely represent field conditions).
Deposition loop uncoated test section showing increase in wax deposition with increase in temperature gradients for different test runs, with uniform wax deposits formed in all cases. Treated vs. untreated loop studies with wax are ongoing.
Figure 4: Deposition loop uncoated test section showing increase in wax deposition with increase in temperature gradients for different test runs, with uniform wax deposits formed in all cases. Treated vs. untreated loop studies with wax are ongoing.
Figure 5: New conceptual picture of gas hydrate formation during the most severe field conditions of transient shut-in/cold restart for a non-surface active hydrocarbon, developed from the extensive deposition flowloop testing achieved under simulated field conditions.
Figure 5: New conceptual picture of gas hydrate formation during the most severe field conditions of transient shut-in/cold restart for a non-surface active hydrocarbon, developed from the extensive deposition flowloop testing achieved under simulated field conditions.

 

Project Start
Project End
DOE Contribution

$1,500,000

Performer Contribution

$374,386

Contact Information

NETL – William Fincham (william.fincham@netl.doe.gov or 304-285-4268)
CSM – Carolyn Koh (ckoh@mines.edu or 303-273-3237)