TX 75083-3836, U.S.A., fax 01-972-952-9435. Abstract

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThis paper presents an overview of BP's approach to Hydrate Management on new Gulf of Mexico (GoM) Deepwater Developments and Operations using the first and second generation (low and high water cut) Anti Agglomerate Low Dosage Hydrate Inhibitors (AA LDHIs). It also describes how these AA LDHIs are used in conjunction with more conventional hydrate management approaches to reach an optimal cost effective field hydrate management solution.The paper also outlines how the challenges outlined by BP and other major oil producers to the oilfield chemical suppliers at various subsea conferences were taken seriously, and how suppliers have risen to these challenges both in terms of cost, chemical technology development and product delivery to the field.Logistics, HSE, chemical injection and life of well operating envelope challenges need careful consideration at all stages of hydrate management and the paper outlines an integrated approach to cover these on a life of asset development. The impact of AA LDHIs and methanol on downstream transportation and refining facilities are also described as well as impacts on crude marketability and crude quality banks.The paper will touch on all these aspects and outline new challenges that are being faced as we move towards High Pressure High Temperature (HPHT) Developments with record water depths and drilling depth challenges.

The BP King West oil well, located in 5400 feet of water in the Gulf of Mexico, is a 2.3 mile tie back to a 17 mile dual active heated King flowline. This heated flowline, receives throughput from two other BP King oil wells, and produces to the Marlin tension leg platform located in 3200 feet of water. Recent reservoir studies predicted a higher water cut than originally anticipated during project sanctioning. Thus, a project was executed to evaluate if the existing hydrate management strategy, which relies on the crude's non-plugging tendencies (contains natural surfactants that act as anti agglomerant), is still adequate or any modifications in operating procedures or facilities were required. Transient simulations were performed to evaluate if hydrates can be prevented by modifying the operating procedures prior to extended shutdowns and during cold restarts. Experimental work was conducted to confirm the non-plugging hydrate characteristics of King West crude and to determine maximum water cut above which the characteristic no longer holds. Transient simulations showed that water flow back by gravity and gas injection could not displace all the water from the King West flowline; thus should not be used as preventive measures. The experimental work confirmed non-plugging hydrate characteristics up to 25% water cut. Since the recent subsurface simulations predict maximum water cut just slightly above 25%, King West hydrate management can still rely on the non-plugging hydrate characteristics of its crude. Introduction King and King West are 100% BP owned and operated oil fields located in the Gulf of Mexico (GoM). The fields consist of three subsea wells, i.e. King D5 and D6 wells and King West D3 well located in a water depth ranging between 5200 and 5400 ft. They are tied back by a 17 mile long, 8 by 12 inches dual active heating flowlines to the Marlin Tension Leg Platform (TLP) located in 3200 ft water depth (Figure 1). D5 and D6 wells are located on the West and East sides of the King flowline, respectively. D3 well is connected to D5 well through a 2.3 miles, 6 by 10 inches pipe-in-pipe flowline. A remotely operated subsea pigging valve located close to the D6 well is normally open. D5 and D6 wells are producing from the same reservoir while D3 well is producing from another reservoir. For reservoir management and water onset purposes, a subsea multiphase flow meter (MPFM) was installed in the jumper between D3 well and King West flowline. Based on the experimental work performed in 2002, the King crude shows non-plugging hydrate characteristics with water cut (WC) up to 10%. Since at the project sanctioning the maximum WC was predicted to be less than 10%, King West hydrate management was designed based on this type of self inhibition characteristic. However, the recent reservoir studies have predicted the maximum WC close to 30%. Therefore, the existing hydrate management strategy needs to be re-visited. Different shutdown and restart procedures were simulated to evaluate if hydrate risks could still be managed through the existing subsea architecture and the topsides facilities. They included allowing the water to flow back to the wellbore by gravity, displacing water to wellbore by gas injection from the topsides, and starting King D5 well first to warm up King West flowline. Injecting low dosage hydrate inhibitors (LDHI) was also investigated based on the existing subsea infrastructure. The experimental work was repeated using King West crude and a more representative water salinity to confirm the maximum WC of this non-plugging hydrate characteristic.

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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%.