Hydrate Inhibition -Optimization in Deep Water Gas Field
- Gaurav Gupta (Reliance Industries Limited) | Sunil Kumar Singh (Reliance Industries Limited)
- Document ID
- Society of Petroleum Engineers
- SPE Oil and Gas India Conference and Exhibition, 28-30 March, Mumbai, India
- Publication Date
- Document Type
- Conference Paper
- 2012. Society of Petroleum Engineers
- 4.6.3 Gas to liquids, 3.4.1 Inhibition and Remediation of Hydrates, Scale, Paraffin / Wax and Asphaltene, 4.3.1 Hydrates, 5.2 Reservoir Fluid Dynamics, 6.1.5 Human Resources, Competence and Training, 7.2.1 Risk, Uncertainty and Risk Assessment, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 4.1.5 Processing Equipment, 4.2 Pipelines, Flowlines and Risers, 4.6 Natural Gas, 4.2.4 Risers, 4.1.2 Separation and Treating, 5.3.2 Multiphase Flow
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Reliance Industries Limited operates D1D3 deep water gas field in Krishna-Godavari basin in India. Water depth at well heads varies from 550 meter to 1150 meter. Horizontal Christmas trees (XMT) are installed on each well head. Hydrate inhibitor is continuously injected at Christmas tree to prevent hydrate formation occurring in the system during all operating conditions. For a properly designed system, hydrate formation should not be possible in normal operation. The only risk of hydrate formation is related to abnormal operating conditions. Hydrate management philosophy should be developed to address the risk of hydrate formation in all condition with minimum hydrate inhibitor injection.
There are always some uncertainties in measurements therefore some level of hydrate inhibitor overdosing is required. In this field Mono Ethylene Glycol (MEG) is injected to prevent hydrate formation. To optimize MEG injection, reliable water and MEG measurements are the important keys. Salinity of slug, pipeline network and different well head water depths are major driving factors to optimize MEG injection.
Hydrate curve is developed either with professional software like PVTsim or rocking cell apparatus in laboratory. In this field minimum required MEG percentage is calculated from PVTsim software. MEG optimization is continuous process and since inception of field, the level of overdosing is reduced from 80% to 15%. Wet Gas Flow Meter (WGFM) is installed on each XMT to measure water production. To verify WGFM water measurement from individual well, other methods of measurement were also developed. MEG injection valves are installed on each XMT which can measure the injection quantity. Correlation is established between different measurement techniques to consider most reliable and accurate value of water and MEG measurement which aided to optimize the MEG injection rates.
Analysis is done through software for some of wells, to find out the feasibility to stop continuous MEG injection in deep water pipeline network system. After this study, continuous MEG injection was stopped in one well. The paper will describe various steps of MEG optimization and level of confidence on hydrate management philosophy.
As the oil and gas industry moves into deeper water and uses longer pipelines, the hydrate risk increases greatly. An effective hydrate management plan, with reliable modeling and analysis tools, is needed to make proper risk assessment. The cost of hydrate remediation in deep water flowline can be extremely high. Hydrate is often regarded as most critical problem in deep water operations. Hydrates are crystalline, "ice-like" compounds composed of water and natural gas. The conditions that tend to promote hydrate formation are low temperature, high pressure and a gas with free water present.
In D1D3 gas field continuous MEG injection is adopted in hydrate management plan to prevent hydrate formation in all conditions. MEG regeneration units are installed at onshore terminal to process limited rich MEG quantity and produce lean MEG. Lean MEG has high percentage of mono ethylene glycol in mixture (90:10; MEG: Water) which is injected at XMT to prevent hydrate formation. Rich MEG (Slug) is mixture of produce water and injected lean MEG. Field has to be operated within the constraint of MEG facility design; hence continuous optimization of MEG injection quantity is the only way to maximize the production from the field.
Description of Subsea Network
The D1D3 deep water gas production field consists of 18 gas production wells that tie back to six subsea production manifolds via eight or ten inch rigid flowlines (Fig. 1). The six subsea manifolds are then tied back to one Deep Water Pipeline End Manifold (DWPLEM) by either 16 or 18 in flowline. From the DWPLEM, two 24 in trunk lines are connected to onshore terminal via Central Riser Platform (CRP). Trunk lines run approximately six km from land fall point to plant and terminate at pig receiver station within the gas plant. The gas from the onshore pipelines is received in the slug catchers at onshore Terminal. Slug is separated in slug catcher and routed to the MEG processing unit.
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