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 can prevent 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.

Colorado School of Mines (CSM) - Golden, CO 80401

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.

Similar 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.

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 leading to catastrophic hydrocarbon emissions. 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.

CSM has demonstrated through extensive testing for more than 2 years in their deposition loop system the hydrate-phobic properties of the DragX 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. Additional key technical milestones and key findings are summarized below.

• Developed new transient conceptual model 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 1). 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 inform industry decisions during operation.

  

   

• Quantification and verification of long term DragX surface treatment durability and effectiveness in the face of pressure exposure/rapid depressurization, cold wall effects, thermal decomposition at high temperature (300℃) for short durations.
• Completed fundamental studies on surface properties to determine that both surface energy and surface roughness have major effects on the deposition and nucleation behavior of hydrates, and the best effects are observed for a combination where both parameters are low.
• Larger-scale extended tests under simulated field conditions show hydrate, wax, and asphaltene resistance using DragX treatment (Figure 2).

• Longer-timescale loop testing under field-simulated conditions showed the treatment to have significant hydrate deposition mitigation properties under both steady state and stringent transient conditions (Figure 3).

• Longer-timescale loop testing under field-simulated conditions showed the treatment to have significant asphaltene deposition mitigation properties (Figure 4).

• Shear force testing of DragX material in asphaltene and wax deposition (Figures 5 and 6) validates that the material is robust enough to maintain functionality in simulated field conditions.

• Validation of two different treatment methods (spray application and flooding) for application of DragX treatment to pipelines and coupons.
• Formulation of DragX optimized and refined for compatibility with common chemicals present in oil and gas production lines (Kerosene, Xylene, JP8, MEG), and viscosity optimized for in-situ pipeline application.
• Establishment of rocking cell apparatus capable of visualization of hydrate formation on DragX treated surfaces.
• Establishment of expanded flowloop with up to 156” of added hydrate deposit testing sections (5x size of previous), and allowing for a significantly increased combination of fluid, flow condition, temperature and pressure.

Findings from this effort demonstrate 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.

Based on the results gathered so far in the project, several strategies are possible for field testing moving forward. While testing at an industry site would be the preferred method, further de-risking and validation activities may be necessary before full field deployment is possible. Below is a brief discussion of options that are under consideration for future commercialization and deployment activities.

• Field deployment – this option would yield the most information about deployment and in-field operation, but also carries the highest risk. There are many possible unknowns in field operation, and subsea application for hydrates would be the most difficult deployment scenario envisioned. Due to the breadth of the research in this project, onshore sites with hydrate, wax or asphaltene deposition challenges would all be candidates for DragX deployment. This option would also allow for either in-situ application or application to new infrastructure, as determined by the opportunity made available by an industry partner. Drawbacks to this approach mostly include the possibility for downtime to the line production during application and/or unpredicted negative effects.

• Third party test loop – Industrial-scale test loops, such as those operated at the Southwest Research Institute, may be an appropriate intermediate test to bridge the gap between field deployments and lab-scale experiments. These larger-scale flowloops can more accurately mimic size, flowrate, and chemical composition of fluids than the lab-scale loop. These experiments could be conducted by applying the surface treatment to test sections within the loop, then performing hydrate deposition experiments, while observing the pressure drop across the treated sections to indicate deposition or sloughing events. An advantage to flowloop testing is that the lines are already heavily equipped with data collection sensors, compared to the field case where additional sensors may need to be installed to monitor the progress of the trial. CSM and Oceanit are currently investigating the possible costs of such trials with SWRI / University of Tulsa, which both have existing larger-scale loop infrastructure.

• In-house test loop – constructing a larger scale test loop would be another possible approach. While this would require significant capital investment into the loop infrastructure, it would also offer the most freedom in experimental parameters and treatment applications. Because the loop would be custom designed, it could accommodate precisely the scaled-up testing that would offer the most validation of the treatment materials. However, it would not be to the same scale as other commercial loops and may not represent as large of a step toward field parameters as a third-party large-scale loop might.

• Modeling – Some modeling efforts have already been performed as part of the research performed thus far. Current modeling development and application efforts focused on the change in wettability of the pipe wall as the primary mechanism for reducing hydrate deposition. However, further research into hydrate deposition as described above has indicated that both the surface roughness and the surface energy are important factors for reducing deposition and nucleation, so further improvements to current models may provide a more accurate picture of how surface treatments, such as DragX, affect the fluid-wall interaction in production scenarios. While modeling can be a strong tool, it is unlikely that modeling alone will lead to scaleup, and deployment efforts needed to commercialize the DragX technology. However, this approach will likely be a part of any effort combined with the above approaches to provide updated predictive information for future applications.

$1,497,543

$374,386

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

Pickarts, M. A., Ravichandran, S., Delgado-Linares, J. G., Brown, E., Veedu, V., Koh, C. A. 2022. Gas Hydrate Deposit Formation in Transient Flowloop Tests and Mitigation with a Surface Treatment. Fuel, 311.

Pickarts, M. A., Brown, E., Delgado-Linares, J. G., Veedu, V., Koh, C. A. 2022. A Comprehensive Investigation into the Effect of a Low Surface Energy Treatment on Gas Hydrate, Asphaltene, and Wax Formation, Deposition, and Adhesion. SPE Journal, 27(01): 410-421.

Pickarts, M. A., Ravichandran, S., Ismail, N. A., Stoner, H. M., Delgado-Linares, J., Sloan, E. D., & Koh, C. A. 2022. Perspective on the Oil-Dominated Gas Hydrate Plugging Conceptual Picture as Applied to Transient Shut-In/Restart. Fuel, 324, 124606.

Brown, E., Pickarts, M., Delgado, J., Qin, H., Koh, C.A., Thapa, S., Nakatsuka, M., Veedu, V. (2022, May). Scale-Up & Modeling Efforts Using an Omniphobic Surface Treatment for Mitigating Solids Deposition, In Offshore Technology Conference. Offshore Technology Conference, OTC-32059-MS.

Pickarts, M. A., Delgado-Linares, J. G., Brown, E., Veedu, V., Koh, C. A. 2021. Surface Treatment Strategies for Mitigating Gas Hydrate & Asphaltene Formation, Growth, and Deposition in Flowloops, In Offshore Technology Conference, OTC-31189-MS.

Pickarts, M. A., Delgado-Linares, J. G., Brown, E., Veedu, V., Koh, C. A. 2020. Evaluation of a Robust, In-Situ, Surface Treatment for Pipeline Solids Deposition Mitigation in Flowing Systems, In Offshore Technology Conference, OTC-30817-MS.

Pickarts, M. A., Croce, D., Zerpa, L. E., Koh, C. A. 2020. Gas Hydrate Formation & Transportability during Transient Shut-In/Restart Conditions, In Offshore Technology Conference, OTC-30857-MS.

Pickarts, M. A., Brown, E., Delgado-Linares, J. G., Blanchard, G., Veedu, V., Koh, C. A. 2019. Deposition Mitigation in Flowing Systems using Coatings, In Offshore Technology Conference, OTC-29380-MS.