TX 75083-3836, U.S.A., fax 01-972-952-9435. ProposalFlow assurance is one of the major considerations when designing a deepwater completion where undesired heat loss through the deepwater riser accelerates the formation of gas hydrates and the deposition of paraffin and asphaltene. In addition, any planned or unplanned shutdown of the well for various well operations for an extended period can result in critical heat loss, which then requires an extended warm-up time to restart the well. In some scenarios, restart of the well becomes impossible without assistance from chemical injection, unless of course, proper thermal insulation was implemented beforehand. Field applications of thermal insulating fluids have demonstrated significant reductions in heat loss by reducing conduction and minimizing thermal convection of the fluid. Such thermal insulating fluids have been applied with great success in many deepwater riser applications during the last several years.For this major deepwater project in the GOM, "how to manage flow assurance" had been identified as key to success of the project from the very beginning of the planning phase. This paper details the selection criteria used in the riser insulation design for the project. Evaluation of several insulation options and combinations of options will be discussed, and the final selection of the preferred insulation method will be presented. The unique design of the deepwater riser enabled the operator to maximize the insulation efficiency by the proposed thermal insulation fluid and to meet the most stringent thermal insulation requirements of this project. Data from downhole temperature and pressure gauges and from the fiber optic DTS system will be presented.
Summary Undesired heat loss from the production tubing, or uncontrolled heat transfer to outer annuli, contributes to the formation of gas hydrates and causes the deposits of paraffin and asphaltene materials that reduce the production rate. The successful application of thermal-insulating fluids in the last several years has demonstrated that such fluids can control heat loss effectively. In some cases, heat loss from the produced fluids caused by conduction and convection can be reduced by more than 90% when compared with traditional packer fluids. Recently, a new thermal-insulating-fluid system with superior thermal properties has been developed. Compared with the existing insulation fluids, the new insulating-fluid system provides high viscosity at a low-shear-rate range to reduce the fluid-convection rate. It also provides lower viscosity at high-shear-rate range to facilitate fluid placement. The new fluid, with improved insulation properties, has proved to be an attractive alternative to the current insulation method for deepwater risers. This paper highlights the development of this new thermal-insulating fluid and its application in deepwater-riser insulation in the Gulf of Mexico (GOM). Laboratory data and field cases are also presented to demonstrate the effectiveness of this fluid system. Introduction Understanding and controlling the thermal environment for oilfield operations has been a concern and research topic since the mid-1960s, when heavy interest was raised in enhanced oil recovery by steam injection. Much of the early attention was focused on steam-injection operations and is well documented in the cited references. 1--3 For applications where the packer annulus was gas-filled, wellbore refluxing was identified as a major reason for heat loss. Wellbore heat losses from the refluxing annulus were 3 to 6 times higher than anticipated for insulated tubing, and were only 30 to 40% less than would be obtained if the injection tubing was not insulated. 3--6 Silicate foams were among the first fluids to be documented as insulating packer fluids in steam-injection applications. 1 In field operations, a solution of sodium silicate is placed in a packed-off annulus and then steam is injected down the tubing. The hot tubing causes the silicate solution to boil, leaving a coating of insulating material---silicate foam from 1/4 to 1/2 in. thick---on the hot tubing surface. Silicate solution that remains in the annulus after steaming for several hours is removed from the annulus by displacing it with water, which is removed by gas lifting or swabbing. The foam is an excellent insulator, with thermal conductivity of about 0.017 Btu/(hr-ft 2 -degree F/ft). However, difficulties have been encountered in boiling off the solutions to form the foam. "Hot spots" were also observed developing adjacent to the uninsulated couplings. 7,8 To prevent thermal refluxing, an insulating fluid that fills the entire annulus was elected as an alternative to the gas-filled annulus. 9 Oils appeared to be suitable material for this application because of their relatively low thermal conductivity [0.08 Btu/(hr-ft 2 -degree F/ft)]. However, natural convection became just as critical and increased heat transfer of oil by a factor of 10 to 20 over molecular conduction. Willhite and his coworkers 9,10 developed an oil-based fluid with reduced apparent-thermal-conductivity value through increasing the viscosity of the base oil, thereby reducing molecular motion. Unfortunately, this two-phase system suffered from long-term suspended-solids settling. Thermal stability was also questionable at the working temperatures. Alternative gelatinous oil-based fluids 11--14 have been developed for the geothermal and oil-recovery applications. The relative thermal conductivity of this type of fluid is approximately 13% that of water. However, the current and future environmental restrictions could limit its application. Furthermore, the long-term incompatibility with various elastomer elements is a critical concern. As an alternative to chemical methods, Purdy and Cheyne 15 applied vacuum-insulated tubing to solve the problem of paraffin deposits in the production tubing in wells near the Arctic Circle. On the basis of a reservoir temperature of 82degreeF and crude oil with a cloud point of 55--57degreeF, computer simulation predicted that the vacuum-insulated tubing could raise the flowing-tubing temperature at the wellhead above the cloud point of the crude oil, thereby solving the historic waxing problems. Installation of th. vacuum-insulated tubing proved to be an apparent technical success. However, the savings on well dewaxing maintenance did not economically justify the installation of the vacuum-insulated tubing. While insulated tubing is an effective method for wellbore insulation, actual heat losses were still observed to be significant. Heat loss through couplings and other internal structures, such as centralizers and valves, was seen to account for up to 50% of the total heat loss. 3,4 To fully achieve the potential of insulated tubing, selected rubber-insulated couplings were tested along with a thermal pipe coating. Although improved thermal performance was obtained, maintaining the dryness of the annulus over a long period is difficult. Heat loss through refluxing could still occur because of damaged and scraped coating and downhole centralizers, valves, and gauges. This problem can be controlled effectively by the use of specially designed aqueous-based (oil-free)-insulating- packer fluids. To secure the insulation of the wellbore so that the heat transfer from the production tubing to the surrounding wellbore, internal annuli, and the riser environment is reduced, Javora et al. 16 have developed a specialized aqueous-based-insulating-fluid (ABIF) system. This fluid is solids free, nondamaging, environmentally friendly, and highly insulating. Fluid viscosity is designed to provide a fluid that is easy to blend and pump into the annulus. Fluid density is controlled by the amount and type of dissolved salt, which provides positive control of wellbore pressure without the risk of solids settling and separation. This wellbore insulating-fluid system has been a success in field applications in the past several years. It has been demonstrated that such fluids, added into either an annulus or a riser, can effectively reduce undesired heat loss from the production tubing or heat transfer to outer annuli.
Flow assurance has been one of the major considerations in deepwater completion design, in which undesired heat loss from production tubing contributes to the formation of gas hydrates and causes the deposition of paraffin and asphaltene materials. Traditionally, controlling annular heat loss has been achieved with the injection of steam, the application of silicate foam, the pressurization of the annulus with inert gas, the use of gelled oil as an insulating packer fluid, and the use of vacuum insulated tubing (VIT). Each of these applications, however, has drawbacks because of either its working mechanism or the higher cost associated with the technology.To secure the insulation of the wellbore and to reduce heat transfer from the production tubing to the surrounding areas, various aqueous insulating fluid systems with superior thermal properties have been developed in recent years. Field applications of these fluids have demonstrated significant reduction in heat loss by reducing conduction and minimizing convection. These thermal insulating fluids have been implemented with great success in more than 75 deepwater riser and packer applications in the Gulf of Mexico (GOM) over the last several years. Case histories have demonstrated that installation of these water-based insulating fluids is an effective alternative to conventional insulation options and is becoming the preferred insulation method in many deepwater projects. This paper will highlight the evolution of different insulating fluid systems and the field experience with each system. Proper testing methods relevant to oilfield flow assurance will be discussed and testing results for these fluids will be detailed. Field cases in the GOM will be summarized, and the effectiveness of these fluid systems will be demonstrated.
This paper overviews the design, development, qualification, and field trial deployment of a hydraulically expandable metal packer that enabled a cementless, zonal, high-pressure acid stimulation program to be accomplished.Achieving effective zonal isolation within long reach horizontal wells using conventional means with cement is challenging to the industry. Achieving effective cement within long step outs is limited by the Equivalent Circulation Density (ECD) (impacted by fracture/pore pressure) or by the inability to achieve effective cement (i.e., without channels/micro annuli) simply due to the sheer length of the horizontal section of the well. Additional challenges are then imposed to achieve zonal isolation within unconventional reservoirs or wells that require high-pressure stimulation.These challenges spurred the design for a metal expandable packer for use in a cementless completion, assembled on a full bore liner, and able to deliver a high annular Delta P seal in a worse case washed-out hole scenario.Material selection to allow hydraulic expansion beyond the yield point of the expanding alloys (i.e., in the plastic region) is a key design consideration for maximizing the post-expansion strength of the expandable metal packer. Continual design, test, and result analysis enabled development of a unique, high-pressure seal between the metal expansion sleeve and the formation. The qualification process was based on the ISO 14310 V3 standard, the industry standard for testing and qualifying plugs and packers. This standard emulates the lifecycle of the packer during acid stimulation and later-life water management.Field-proven zonal pressure isolation will be illustrated with real-time zonal pressure data from the field trial in an offshore field. The well will demonstrate cement-less liner completion efficiency with sixteen expandable metal packers to achieve five isolated, stimulated, and subsequently producing zones and three water shut-off zones.In closing, the paper will summarize ongoing developments and how the open hole expandable metal packer is meeting the unique challenges of annular high-pressure containment. The many benefits to operators include fast setting under surface control with increased reliability and certainty for success.
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 thermalinsulating 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.
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