Water-Based Insulating Fluids for Deep-Water Riser Applications
- Paul H. Javora (BJ Services Company) | Xiaolan Wang (BJ Services Company) | Richard F. Stevens (BJ Services Company) | Ricky G. Pearcy (BJ Services Co. USA)
- Document ID
- Society of Petroleum Engineers
- SPE Projects, Facilities & Construction
- Publication Date
- March 2006
- Document Type
- Journal Paper
- 1 - 6
- 2006. Society of Petroleum Engineers
- 1.6 Drilling Operations, 4.3.3 Aspaltenes, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 4.2 Pipelines, Flowlines and Risers, 2 Well Completion, 5.9.1 Gas Hydrates, 4.5 Offshore Facilities and Subsea Systems, 1.11 Drilling Fluids and Materials, 1.7.5 Well Control, 5.2.2 Fluid Modeling, Equations of State, 4.2.3 Materials and Corrosion, 5.4.6 Thermal Methods, 1.7.6 Wellbore Pressure Management, 2.7.1 Completion Fluids, 1.8 Formation Damage, 2.4.3 Sand/Solids Control, 4.2.4 Risers, 3 Production and Well Operations, 2.1.7 Deepwater Completions Design, 4.3.4 Scale, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 4.3.1 Hydrates
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Uncontrolled heat transfer from production tubing to outer annulus—especially in deepwater riser sections—can cause the deposition of sludge, paraffin, and asphaltene materials; contribute to the formation of gas hydrates; and limit shut-in time for unplanned downtime or remedial operations. Generally, deepwater risers can be insulated externally or insulated by placing nitrogen gas into the riser annulus. In recent years, a new water-based thermal-insulating fluid system has been developed and used in field applications. This new system reduces convection and provides a rheological profile to facilitate fluid placement into the riser annulus. This system has been successfully used in deepwater risers in the Gulf of Mexico (GOM).
Laboratory-scale equipment and a full-scale test well were constructed to evaluate the thermal-insulation properties of fluids. This paper details the testing procedures and methods. Steady-state heat-transfer- and cool-down-test results on the new insulation fluid were determined and compared to conventional fluids. These superinsulating fluids were found to be vastly superior to brine and measurably better than conventional water-based insulating fluids. Surprisingly, when compared to nitrogen (air) or argon, the superinsulating fluids provided enhanced protection during cool down. Field cases in the GOM are summarized to demonstrate the effectiveness of this fluid system.
Understanding and controlling the thermal environment of oilfield operations has been a concern since the 1960s. Early attention was focused on hot water and steam-injection operations (Penberthy and Bayless 1974; Eisenhawer et al. 1981; Aeschliman et al. 1983) and applications in which insulation was provided by filling the packer annulus with inert gas (Aeschliman et al. 1983; Galate and Mitchell 1985; Aeschliman 1985; Willhite and Griston 1987). Even with gas-filled annuluses, heat losses were observed to be higher than expected.
Liquid-filled annuli were also examined using oil, which has a relatively low thermal conductivity [?0.08 Btu/(hr•ft•°F)]. Heat losses were again observed to be higher than expected. In this instance, the heat loss from nonviscosified oil was associated with significant convection within the annulus (Willhite et al. 1967; Willhite 1967). However, thixotropic oil-based fluids that have a relative thermal conductivity approximately 13% that of water have been reported (Son et al. 1983; Yousif et al. 1994; Ashford et al. 1990; Suarez et al. 1995). While these fluids can be weighted to higher densities, they potentially suffer from solids settling, emulsion destabilization, incompatibility with elastomer elements, and future environmental restrictions. Water-based silicate foams with low thermal conductivity [?0.18 to .27 Btu/(hr•ft•°F)] were evaluated by Son et al. (1983), but the system was found difficult to control downhole, and the pipe was vulnerable to the development of hot spots (Penberthy and Bayless 1974; Willhite et al. 1967; Willhite 1967). Dry foam silicate (Penberthy and Bayless 1974) and silica aerogel (Kuperus et al. 2001) systems were reported to be 10 times more effective than liquid brine. Purdy and others evaluated vacuum-insulated tubing (VIT) (Purdy and Cheyne 1991; Davalath and Barker 1995; Feeney 1997), and as expected, its application was found successful but expensive. Nonetheless, heat loss through couplings, valves, gauges, centralizers, and damaged or scrapped coatings can dramatically increase heat loss from a VIT system. A unique system to mitigate heat loss uses a pipe-in-pipe arrangement coupled with electrical current to generate heat and prevent gas-hydrate plugs in pipelines (Von Flatern 2001).
A recent paper (Dzialowski et al. 2003) described the evaluation of oil-based and glycol-based insulating fluids designed for use in aluminum riser applications and in the measurement of thermal conductivity based on the nonsteady-state hot-wire method. A nonweighted oil-based system was selected for further testing.
An overview of various applications for insulating packer fluids, including deepwater completions, has been presented (Pearcy and Johnson 2000; Moe and Erpelding 2000). Recent articles by Javora et al. (2002) and Wang et al. (2005) detail the advances made in formulation and use of water-based insulating fluids.
To control the total heat loss from produced fluids to the surrounding wellbore, internal annuli, and riser environments, specialized water-based insulating fluids were developed. Fluid composition is controlled to provide inherently low thermal conductivity, effective viscosity, and favorable environmental characteristics. These water-based fluids are oil free. Fluid density is controlled by the amount of dissolved salt and can be varied to provide positive wellbore-pressure control without the risk of solids settling.
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