Hydrate Inhibition Design for Deepwater Completions
- Janardhan Davalath (Mentor Subsea) | J.W. Barker (Exxon Co. Intl.)
- Document ID
- Society of Petroleum Engineers
- SPE Drilling & Completion
- Publication Date
- June 1995
- Document Type
- Journal Paper
- 115 - 121
- 1995. Society of Petroleum Engineers
- 6.5.3 Waste Management, 2.1.7 Deepwater Completions Design, 4.2.5 Offshore Pipelines, 5.9.1 Gas Hydrates, 5.2 Reservoir Fluid Dynamics, 4.2.4 Risers, 5.6.4 Drillstem/Well Testing, 4.2 Pipelines, Flowlines and Risers, 4.1.5 Processing Equipment, 2.2.2 Perforating, 1.6 Drilling Operations, 4.1.2 Separation and Treating, 2.7.1 Completion Fluids, 4.3.1 Hydrates, 5.3.2 Multiphase Flow, 4.2.3 Materials and Corrosion, 3.4.1 Inhibition and Remediation of Hydrates, Scale, Paraffin / Wax and Asphaltene, 2 Well Completion, 4.6 Natural Gas
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This paper will review the design considerations for gas hydrate prevention in deepwater well completions. The influence of seafloor temperature, wellbore pressure, water production rate and composition of gas on hydrate inhibition system design will be discussed. The impact of various inhibitors will be discussed in relationship to the design of the system and potential handling problems. Examples will review design considerations for sizing of subsea inhibitor lines, selection of injection depth below the seafloor and hardware requirements. Case histories of inhibitor injection systems used in deepwater completions and during testing of deepwater exploration wells will be reviewed. The benefits of insulated tubing to enhance inhibition design will be discussed. Also, a method will be introduced that can be used to estimate the maximum inhibitor injection rate to avoid salt precipitation from completion fluid or produced water.
As drilling and production operations expand into deepwater environments, operators need to consider the potential risk of gas hydrate formation in wellbores, subsea pipelines and subsea equipment during both drilling and production operations. Gas hydrates are ice-like solids that form from gas and water under combinations of high pressure and moderately low temperatures. The ice-like structure occurs when the water molecules form cage-like structures around the guest gas molecules. In deepwater wellbores and pipelines, gas hydrates can potentially form and plug flow passages. Figure 1 illustrates where hydrates can form in a deepwater well.
There has been extensive research on gas hydrate formation during the drilling phase of deepwater wells. This paper, however, reviews the subject of gas hydrate formation in deepwater production and testing operations.
The risk of forming hydrates is greatest when the well is cold. This condition usually occurs during production start-up or while the well is shut-down following a period of flow. Hydrates can also form while the well is flowing if the well temperature and pressure present the right conditions.
There are several consequences of forming a hydrate plug:
1. Well flow rate can be reduced significantly or production could completely stop.
2. Plugs can make it difficult to run wireline tools down the tubing string.
3. Hydrate plugs can make it difficult to open or close downhole valves to control the flow of produced fluids into the tubing or from the annulus.
There are several possible solutions to mitigate the risk of hydrate plugging in deepwater production tests or deepwater completions: (1) a hydrate inhibitor can be injected into the wellbore; (2) the tubing can be insulated; (3) the wellbore can be heated. The most common solutions are to use inhibitors or insulation.
|File Size||1 MB||Number of Pages||7|