Water Shutoff Using an Inflatable Composite Sleeve Polymerized In-Situ: A Case History on Forties Delta
- J. Leighton (Drillflex) | J.L. Saltel (Drillflex) | J. Morrison (BP plc) | R. Welch (BP plc) | J. Pilla (Schlumberger)
- Document ID
- Society of Petroleum Engineers
- SPE Production & Facilities
- Publication Date
- May 2001
- Document Type
- Journal Paper
- 97 - 105
- 2001. Society of Petroleum Engineers
- 4.1.2 Separation and Treating, 3.1.2 Electric Submersible Pumps, 4.2.4 Risers, 2.4.3 Sand/Solids Control, 3.2.5 Produced Sand / Solids Management and Control, 4.3.4 Scale, 1.14 Casing and Cementing, 3.1 Artificial Lift Systems, 4.5 Offshore Facilities and Subsea Systems, 1.6 Drilling Operations, 2.2.2 Perforating, 3.3.1 Production Logging, 5.6.4 Drillstem/Well Testing, 4.1.5 Processing Equipment, 3 Production and Well Operations, 3.1.6 Gas Lift, 5.2 Reservoir Fluid Dynamics
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A new technology based on using in-situ polymerization of composites has been developed and has been used to shut off water-producing perforations for the first time on Forties Delta. By exploiting the deformability of an unpolymerized flexible composite and the excellent mechanical characteristics of a polymerized composite, it was possible to run an expandable patch-through tubing and set in the liner below. The principles of running the composite patch on electric wireline and the specialized surface and downhole tools are described, along with the setting procedures and events offshore.
Results of this operation have shown an inflatable composite sleeve can be used as an efficient and cost-effective solution for reducing unwanted water production.
Different techniques used to sustain production in the North Sea have led to an increasing need for through-tubing zone isolation. Since 1994 a new technique based on polymerizing resins in-situ has been developed. Initially launched with support from the Production Engineering Assn. (Europe) and participation by BP plc, Elf, Norsk Hydro, Saga, Shell, Statoil, and Total, technology was developed and tested in 1995 and 1996.1 The first field operations were carried out in 1997, and in October it was used for the first time for shutting off a water-producing zone on Forties Delta 4-1.
This paper explains how the inflatable composite patch technology works, and describes the development before beginning field use. It examines why an intervention was necessary on well FD4-1, and the different options considered. It further describes the job, the problems encountered, solutions found, and the lessons learned. It looks at the economic consequences, and gives a brief description of two other composite patch operations carried out on the Forties field. The authors discuss the advantages and disadvantages of the composite patch, and look at alternative uses of in-situ polymerization technology.
The principle of the technology is to use an inflatable setting element (ISE) to convey a composite sleeve into the well. The composite sleeve is manufactured using thermo-setting resins and carbon fiber, so it will be soft and deformable when running in hole. Once the tool is opposite the zone to be treated, the ISE can be inflated to push the composite sleeve into place against the inside of the casing, where it is heated to polymerize the resins. Then the ISE is deflated and extracted, leaving the composite sleeve as a hard pressure-resistant lining inside the casing.
A running tool piloted from surface is used to run and position the product. Fig. 1 illustrates the assembly in place. A surface-control module activates a pump in the downhole running tool and begins inflation of the ISE. Fig. 1b shows the lower end inflating first to anchor the composite sleeve in place. Fig. 1c shows the inflation moves upwards progressively so no well fluid can become trapped behind the permanent sleeve and create a hydraulic lock. This movement is managed by a series of progressive expansion rings (PER's) which break in sequence.
Fig. 1d shows the product fully inflated and heating begins. Electric current from the surface is applied to a series of resistances inside the ISE. The temperature is controlled from the surface to verify the polymerization process and ensure that all parts of the permanent sleeve are fully hardened.
After polymerization, the pump is reversed to deflate the ISE (Fig. 1e). When the pressure has been bled-off, the ISE is pulled through the hardened composite sleeve as shown in Fig. 1f and recovered at the surface with the running tool.
Trials and Testing.
Considerable development was needed to produce suitable materials for this application. It required a resin with the necessary characteristics for use in an oil-well environment, but did not require excessive amounts of energy to polymerize; an elastomer with an expansion coefficient sufficient for through-tubing operations at the same time as being heated to 200°C for polymerization; and fibers which would give a suitable pressure rating to the finished sleeve.
An epoxy-based resin, developed for Drillflex by the Inst. Français du Pétrole (IFP), a specially formulated hydrogenated nitrile, and woven braids of carbon fibers were developed. The first products were tested in a dummy well in simulated downhole conditions which indicated that between 600 to 2,400 W/m of set patch were required for successful polymerization.
The seven-conductor openhole logging cable was selected as it could be used to supply the most power downhole of all the standard oilfield cables.
Before the first field trials took place, more than 50 tests were carried out in a dummy well which simulated downhole conditions of 200 bar, 85°C, and used corroded tubings.
After these had been successfully completed, the technology was used in North America and the North Sea in tubing before being used for sealing perforations for the first time on well FD4-1.
Field and Well Conditions
The Forties field was one of the first discovered in the North Sea, and one of the largest. First oil was delivered in 1975, with the maximum oil production rate of more than 500 thousand B/D achieved in the period 1978-80. The development consists of four main field production platforms and one electrical submersible pump (ESP) satellite platform. The oil in place is estimated to be more than 4,000 million bbl, with reserves of approximately 2.5 million bbl (60% recovery). To date, more than 90% of these reserves have been produced. Table 1 gives field data.
Since the late 1980's when artificial lift facilities (gas lift) were installed on the four main field platforms, more than 50 wells either have had their production liner replaced, or have been drilled to a new infill location. In the majority of cases, 51/2-in. gas lift completions have been installed. The production liners have been either 41/2 in. or 7 in., depending on the type of sidetrack required. The applied drawdown on wells within the Forties field is limited normally by sand production, and is typically within the range of 35 to 55 bar.
In 1997 the field oil production rate was 86,000 B/D, with an associated water production of 270,000 B/D, giving an average water cut of 76%.
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