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

This paper describes the flow assurance challenges faced during the development of a multi-well field located approximately 27 KM (17 miles) from the host facility and how those challenges have been solved using pipe-in-pipe active heating. The selection criterion demonstrates that active heating has advantages over chemical options. Active heating systems are a practical and cost effective development option for control of hydrate and wax deposition during operation and planned or emergency shutdowns. Active heating provides increased operational flexibility through control of the pipeline temperature above the hydrate formation and wax deposition temperatures, allowing for prolonged shutdowns, conditioning of the line for resuming operation, or melting of hydrate or wax plugs formed during extended shutdowns. These flowlines were constructed by Allseas' Solitaire pipelay ship and the S-Lay method and commissioned successfully using treated fresh water for hydrotesting to eliminate contamination, particularly for the annulus section.A Glycol -water solution was selected as the heat transfer medium for its heat transfer efficiency, low corrosivity and inherent microbiological control (biocide) properties. The performance of the first active heating system in the Gulf of Mexico has exceeded the design criterion and provided better heating efficiency than anticipated. 10. Private Communication, Union Carbide Corporation. 11. Thermal Expansion Design and Implementation, Harrison, G. E.; Brunner, M. S.; Bruton, D. A. S., OTC 15310, OTC 2003, Houston, TX.

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%.

In this paper a cold pipe continuous wax remover and slurry making device is described for use in long distance subsea tie back applications using single bare flow lines (Cold Flow). The basic principle of the Cold Flow solution is to eliminate the temperature differential between the production fluids and the walls of the flow line, thus eliminating the deposition of wax on the flow line walls. This is accomplished by cooling the fluids to ambient temperature and precipitating solid waxes in a controlled section of the pipeline (Treatment Loop) before entering the flow line. To increase the efficiency of cooling, and hence reduce the length of the treatment loop, wax deposits that form on the walls of the loop are constantly removed by using a continuously circulating unique mechanical device (WaxEater). The WaxEater consists of a train of circular discs, each having a diameter that leaves a small clearance within the inside diameter of the Treatment Loop. The WaxEater continuously circulates in the specially designed Treatment Loop, propelled by the produced fluids, and sweeps the wax deposits off the inner wall of the loop. The concept was successfully tested in an 800-ft fl loop. Several test runs were performed using waxy Gulf of Mexico (GoM) crude oils, with and without the WaxEater. This paper presents the results of these tests.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe King West single well deepwater development is a 2.5 miles, 6" flowline tieback to the existing King system western flowline in water depth of 5,500 ft.The King West Project Team was faced with high costs and complex methods for hydrotesting and tying this into the King subsea system. The conventional BP GoM Projects subsea flowline hydrotest method is to pump seawater or fresh water, pressurize it, and test for any possible leaks. Upon completion, the water is discharged subsea or displaced using nitrogen.For deepwater flowlines, residual water from the hydrotest must be inhibited to prevent hydrate formation during initial well startup. However, the bathymetry of the King West flowline indicated that inhibition by methanol displacement alone could not achieve this and complex nitrogen de-watering would be needed.The Project Team suggested investigating the possibility of using natural hydrate inhibition properties of high salinity inhibited completion brine instead of fresh water for flowline hydrotesting.This novel approach has major benefits. It reduced environmental impact and personnel exposure, procedure complexity, risks in dewatering operations; process upsets and allows the hydrotest fluid to flow back with well fluids through the host facility process then safely discharged. Moreover, the well startup time was reduced by approximately two days.In order to fully understand the hydrate inhibition properties of calcium chloride (CaCl 2 ) brine, several tests were conducted at local labs. These test results showed that using a CaCl 2 brine with a concentration of 11.2 ppg (33.9 wt%) would be best for King West hydrotesting.Eight different hydrate prediction softwares were compared with experimental hydrate formation data for high salinity brine-hydrocarbon systems. Comparisons showed only one prediction software matches the experimental data within a close range.The other key finding observed from the experimental data is that CaCl 2 depression of hydrate formation temperature does not reach a maximum at increased concentrations, instead the hydrate inhibition capability continue to increase with further increase in CaCl 2 concentration.The pressurized crystallization point (PCT) for 11.2 ppg CaCl 2 brine at 15,000 psi was measured as 15 o F, which is well below the seabed temperature for King West flowline.The King West subsea system was successfully hydrotested on May 29-30, 2003 by using 11.2 ppg CaCl 2 brine inhibited with corrosion inhibitor and oxygen scavenger. Production was started with no associated facility upsets, hydrate formation or well downtime.