Continuous Application of Anti-Agglomerant LDHI for Gas-Condensate Subsea Tieback Wells in Deepwater Gulf of Mexico
- Zubin D. Patel (MULTI-CHEM) | Michael Dibello (ENI Petroleum) | Kevin Fontenot (Eni US Operating Company Inc.) | Anthony Guillory (Eni US Operating Company Inc.) | Richard Hesketh-Prichard (Manatee, Inc.)
- Document ID
- Offshore Technology Conference
- Offshore Technology Conference, 2-5 May, Houston, Texas, USA
- Publication Date
- Document Type
- Conference Paper
- 2011. Offshore Technology Conference
- 3.4.1 Inhibition and Remediation of Hydrates, Scale, Paraffin / Wax and Asphaltene, 4.3.1 Hydrates, 4.2 Pipelines, Flowlines and Risers, 4.5 Offshore Facilities and Subsea Systems, 4.3.4 Scale, 4.1.2 Separation and Treating, 4.5.7 Controls and Umbilicals, 5.2.1 Phase Behavior and PVT Measurements, 5.3.2 Multiphase Flow, 5.9.1 Gas Hydrates, 4.1.5 Processing Equipment, 5.2 Reservoir Fluid Dynamics, 2.3.1 Remote Monitoring, 2.5.2 Fracturing Materials (Fluids, Proppant), 4.6 Natural Gas, 4.2.3 Materials and Corrosion, 4.3 Flow Assurance
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The formation of natural gas hydrates continues to be a common flow assurance challenge, particularly in deepwater production systems. When water and natural gas are present in an environment of cold temperatures and high pressures, hydrates can form causing partial or complete blockage of production. Prevention of hydrate blockages via chemical inhibition is typically accomplished by using either thermodynamic inhibitors (methanol, ethylene glycol) or Low Dosage Hydrate Inhibitors (LDHIs).
The production system described herein consists of four subsea gas wells (2,200 feet water depth) tied back via 19-mile dual flowlines to the host platform. Hydrate control is required due to the condensed water from the gas entering the hydrate forming region within a few hundred feet of the wells and continuing through 19 miles of uninsulated flowline to the platform. The production system was designed and engineered for the use of LDHI for hydrate control to avoid the large volumes of methanol would be required both in early field life (condensed water) and later field life (formation water).
Field conditions dictated (Kelland 2010, Patel and Russum 2010) the use of an Anti-Agglomerant (AA) LDHI versus a Kinetic Hydrate Inhibitor (KHI) due to the high subcooling, low water cut, and performance with long shut-ins on a long subsea tieback. However, there were several challenges to conventional AA chemistries presented by this application. Some of these challenges included treating condensed water in condensate, high gas-to-oil ratio (GOR), rapid cooldown of fluids, continuous injection and impact on topsides fluid processing. As such, a new AA chemistry was developed to perform under the expected field conditions for all stages of the field life.
Overall, there were several critical steps to the successful development and deployment of a new AA for use with condensed water on gas-condensate deepwater production system. Herein, we describe the project design and development, the chemical design, testing, and planning done before start-up, the transition from methanol treatment to LDHI, and the general results and lessons learned to date for this project. This project represents one of the few uses (Klomp et al. 2004) of continuous AA to treat condensed water in a long gas-condensate tieback in deepwater.
The continuous use of AA-LDHI in high-GOR gas systems with only condensed water is one of the most challenging applications for this type of chemistry, both from a performance aspect and topsides fluid treating. Conventional wisdom has suggested that many AAs do not perform well in waters containing less than about 1.5-3.0 wt% salts (Klomp et al. 2004) or high-GOR gas-condensate systems (Clark et al. 2005). This is thought to be due primarily to the rapid formation of hydrates in condensed water with a fast cooldown rate (giving a higher subcooling and formation rate) versus the chemical's ability to disperse to the forming hydrate crystals and minimize particle size to maintain an easily flowable slurry. Moreover, with AA chemistries being surfactant in nature, the continuous use of AAs can present topsides issues with water quality and/or emulsion problems (Webber 2009).
Once the chemistry was developed and tested for both performance and topsides impact, the transition from methanol to the AA in the field required considerable planning and cooperation between the producing company and the chemical service provider. The subsequent field optimization, continuous monitoring, and necessary adjustments to the treatment program proved to be critical in the successful application of the new AA.
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