in Wiley InterScience (www.interscience.wiley.com).It was shown that flowline hydrate plugs dissociate radially not horizontally; this has significant implications for the remediation of a hydrate blockage, a major flow assurance problem. Over a decade of measurements has enabled models to estimate the dissociation time for hydrate plugs in flowlines, using radial heat transfer with two moving boundaries. Three different plug dissociation scenarios were modeled: singlesided depressurization, two-sided depressurization, and dissociation by radial electrical heating. The models were able to replicate the experimental observations with no fitted parameters. Structure I hydrate was found to dissociate faster than structure II; this was attributed to the different latent heats between the structures. These results indicate that hydrate dissociation in these systems is

This work presents the results from experiments and modeling of tetrahydrofuran single crystal hydrate growth. The purpose was to study growth kinetics, independent of mass transfer and heat transfer. We used a single crystal apparatus, at stoichiometric concentrations of tetrahydrofuran and water, varying the fluid shear to decrease the boundary layer at the crystal surface. We found that with extreme precautions to totally eliminate mass transfer and to minimize heat transfer via high shear, it is very difficult to obtain reliable kinetic constants for the single hydrate crystal growth system. We eliminated mass transfer, but were only able to reduce the heat transfer resistance to a value of about 10% of the total resistance (i.e., 90% kinetic resistance) at the lowest value of subcooling. We found that growth rate increased with the driving force (i.e., subcooling) and established that the growth process occurred by a step mechanism. We only measured the fluid phases in order to obtain hydrate phase kinetics. The results of this work suggest that assessment of heat transfer, previously ignored in crystal growth kinetic studies is vital for accurate hydrate kinetics.

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.

In this work, we concentrated on hydrate dissociation by the method of depressurization (two-sided and one-sided). Experiments focused on formation of hydrate plugs and subsequently their dissociation by both the methods to develop a database. The experiments lead to broadening our limited knowledge on hydrate dissociation by depressurization. The work was conducted with both structure I/structure II type of hydrates. The mechanism of hydrate dissociation (radial or axial) was studied in this work. Work on hydrate dissociation modeling is very limited. Peters (1999) had modeled the two-sided hydrate dissociation as a radial moving boundary model. The model is capable of predicting the hydrate dissociation time and the total time for plug melting. A one-sided depressurization model was developed that predicts the time to re-start the flow. The re-start time depends on the downstream pressure, length, porosity and permeability of the hydrate plug. A safety model was developed that assesses the hydrate plug movement when subjected to pressure gradients. The safety model provides the user a safety optimum downstream pressure for one-sided depressurization. The one-sided model was verified with laboratory and Tommeliten field plugs. The model predicted that the Tommeliten field plugs were re-started when the annulus spacing was 8% of pipeline radius. The safety model compared to the simulations of Xiao et al. (1998), and predicted higher, but comparable plug velocities. As a result of this work, operators should be able toConduct one-sided depressurization safelyPredict time when flow can be re-started A user-friendly Visual Basic front-end program (CSMPLUG) was developed that incorporates one-sided depressurization, two-sided depressurization and safety simulator. Experiments The purpose of the experiment was to form hydrates from ice and to dissociate the hydrate plug. The experiments were conducted in an unstirred batch reactor under isobaric and isothermal conditions. The formation experiments were conducted under variable temperature and pressure. Experimental conditions were limited to pressures between 0 and 3000 psig and temperatures between -10C and 5C. Experimental Equipment In the present work, a new long cell was built in order to study effects of length/diameter on plug dissociation times. Figure 1.1 shows the schematic of the long cell. The stainless steel cell is 0.92 m long, has an internal diameter of 0.0254 m and an internal volume of 0.00047 m3. The new long cell had a threaded end caps sealed by a rocket seal?. Figure 1.1: Schematic of the Long Cell (not to scale) (AVAILABLE IN FULL PAPER) All other parts of the apparatus (Figure 1.2) were connected with 0.006 m stainless steel tubing connected with Swagelock fittings. An Omega/Ashcroft pressure transducer, with a pressure range between 0 and 5000 psig, was used to continuously monitor the pressure in the cell. The accuracy of pressure transducer was + 25 psig. The temperature inside the cell was determined with the use of five type T (Copper-Constantan) thermocouples. The location and numbers of the thermocouples is also detailed in Figure 1.1. The temperature of the gas just outside each end of the cell was also measured using type T thermocouples. The temperature of the bath was monitored using a platinum resistance temperature detector (RTD).

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.