Experience in AA-LDHI Usage for a Deepwater Gulf of Mexico Dry-Tree Oil Well: Pushing the Technology Limit
- Amrin F. Harun (BP Egypt) | Gee S. Fung (BP) | Muge Erdogmus (BP America)
- Document ID
- Society of Petroleum Engineers
- SPE Production & Operations
- Publication Date
- February 2008
- Document Type
- Journal Paper
- 100 - 107
- 2008. Society of Petroleum Engineers
- 2.2.2 Perforating, 4.5 Offshore Facilities and Subsea Systems, 4.2 Pipelines, Flowlines and Risers, 4.6 Natural Gas, 4.2.4 Risers, 5.2.2 Fluid Modeling, Equations of State, 4.5.7 Controls and Umbilicals, 4.1.5 Processing Equipment, 4.2.3 Materials and Corrosion, 5.2 Reservoir Fluid Dynamics, 4.1.2 Separation and Treating, 3 Production and Well Operations, 5.6.11 Reservoir monitoring with permanent sensors, 5.3.2 Multiphase Flow, 5.4.2 Gas Injection Methods, 3.1.6 Gas Lift, 4.3 Flow Assurance, 3.4.1 Inhibition and Remediation of Hydrates, Scale, Paraffin / Wax and Asphaltene, 4.3.1 Hydrates
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A dry tree well in the Gulf of Mexico (GOM) has been producing oil with more than 50% water cut. This raises a concern, because the existing Anti-Agglomerants Low Dosage Hydrate Inhibitor (AA LDHI) used during extended shutdowns and cold restarts, is effective only up to 50% water cut. Because more time and resources would be required to bring a new AA LDHI, more detailed analysis were performed to evaluate the possibility of managing hydrate risks through operating procedures. It was found that during extended shutdown, the wellbore fluid can be pushed down below the mudline using the dry gas from the glycol contact tower followed by diesel or methanol. Thus, it eliminates the hydrate risk during extended shutdowns. Confirmed by the actual data, the cold restart simulations found the warm-up time in the wellbore to be less than an hour. The actual data also show the cumulative water cut one hour after restart was found to be below 50%. The cold restart procedures have been updated with the strategy to outrun the water and come out of the hydrate condition as quickly as possible. Since then, the well has been brought on production using the existing LDHI without any hydrate problems, even with a water cut approaching 90%.
Under favorable conditions of high pressure and low temperature, hydrocarbons and water can combine to form crystalline solids, which resemble wet snow or ice, that are also called hydrates. The crystal structure is composed of cages of hydrogen bonded water molecules which surround "guest?? hydrocarbon molecules such as methane, ethane, and propane. The thermodynamic stability of these structures increases as pressure increases and temperature decreases (Sloan 1998). These ice-like structures could agglomerate to block tubing, flowlines, and/or facilities.
To determine the conditions of temperature and pressure under which hydrates can form, the best approach is to conduct experimental measurements on the appropriate hydrocarbon/water mixture. However, this is not always practical. Thus, the method for predicting hydrate behavior using thermodynamic models is more common. A thermodynamic model is used to calculate the hydrate equilibrium curve, also known as the hydrate disassociation curve. The hydrate disassociation curves for Well A-4 gas is presented in Fig. 1. The curves are generated based on gas composition given in Table 1. The reason to use the hydrate curve based on gas composition instead of combined reservoir fluid composition is to give more conservatism, although it was found that the difference between the two curves happens to be very small. The combination of pressure-tempreature (P-T) condition on the right side of the curve is safe, while the left side is subjected to hydrate formation. The curve shifts by approximately 15°F because of the 13.3% salinity of the produced water, which will have a major impact in flow assurance analysis. This shows the importance of having the accurate water chemistry analysis in generating the curves. Based on the saline hydrate curve and maximum shut-in wellhead pressure of 3,000 psia, the temperature in the entire tubing must stay above 60°F to be free from hydrate risks.
To keep the operating condition of a well or a hydrocarbon production system free from hydrate risks, several techniques can be applied. Mechanically, the flow conduit along the production path can be insulated to keep the heat carried by the reservoir fluid contained within the flow conduit. However, depending on the overall heat-transfer coefficient of the flow conduit and the ambient temperature, the operating condition could soon enter into the hydrate risks condition during shutdown or restart. Thermodynamically, hydrate inhibitor (such as methanol or glycol) can be injected into the flow stream to shift the hydrate equilibrium curve to the left; thus, when the flow conduit cools down to the ambient temperature during shutdown or restart, it stays on the right side of the hydrate curve. However, shifting the hydrate curve to the left until the operating condition during any production scenario saved from hydrate risks might require an excessive amount of inhibitor that would then require larger injection and storage systems for that inihibitor. If the injection system, such as a pump or umbilical, is already in place and has limited capacity, well-production rates might have to be choked back to keep the effectiveness of the inhibitor. One of the possible solutions for this problem is by injecting a low-dosage hydrate inhibitor (LDHI). By definition, LDHI should be able to manage hydrate risks with a lower amount as compared to the conventional inhibitor such as methanol or glycol.
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