The Transfer of Through-Tubing Drilling Technology Between Provinces
- John W. Morrison (BP plc)
- Document ID
- Society of Petroleum Engineers
- SPE Drilling & Completion
- Publication Date
- June 2004
- Document Type
- Journal Paper
- 65 - 71
- 2004. Society of Petroleum Engineers
- 3.1.6 Gas Lift, 1.6.6 Directional Drilling, 1.5 Drill Bits, 1.6.8 Through Tubing Rotary Drilling, 3.1 Artificial Lift Systems, 4.5 Offshore Facilities and Subsea Systems, 3.1.2 Electric Submersible Pumps, 3 Production and Well Operations, 1.14 Casing and Cementing, 1.6 Drilling Operations, 2.2.2 Perforating, 5.1.2 Faults and Fracture Characterisation, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 1.10 Drilling Equipment, 1.6.1 Drilling Operation Management, 1.11 Drilling Fluids and Materials, 2 Well Completion
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Many companies operate on a global basis. Often, a new idea or technology can make a step change in the economics or performance in a particular province or field. That leaves the company with the enviable problem of understanding how and where it could impact operations in other areas of the world.
One area in which BP has had such success is in the North Slope of Alaska, where through-tubing drilling (TTD) has made a dramatic impact on their infill-drilling program. In fact, Alaska had developed two distinct TTD techniques - coiled-tubing drilling (CTD) and through-tubing rotary drilling (TTRD). This paper discusses how the technology was transferred to the North Sea. The subject is tackled on three levels:
Transfer of practical knowledge.
Tactical choice on the optimum technique.
Determination of the strategic value of the technology.
This paper illustrates what needs to be done to ensure a successful business outcome when trying to gain the benefits of a new technology in a different operating environment.
To illustrate the issues, this paper presents performance information on both TTD techniques used in Alaska, discussing their differences and why the application of CTD, in particular, has made such a significant impact. It then discusses how the North Sea's operating environment differs from the North Slope, how this influenced the choice of technology, and the potential magnitude of the benefit that could be realized.
By the end of the analysis, it became clear that the solution and strategy for the North Sea had to be different from that of Alaska, and it became apparent why CTD has struggled to make an impact in the North Sea.
In 1997, there was significant interest in exporting TTD technology to the North Sea, in part because of the success of the CTD program in Prudhoe Bay. An initial feasibility study showed that the largest potential was probably within the Forties* field. While a number of other fields were also interested, it was decided that the best way to transfer the technology was to target the first implementation in Forties.
The Forties field was one of the first discovered in the North Sea and is one of the largest. First oil was delivered in 1975, with the maximum oil-production rate of more than 500,000 B/D being achieved during 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 billion bbl, with recoverable reserves of approximately 2.5 billion bbl (60% recovery). To date, more than 90% of these reserves have been produced.
In the late 1980s, artificial-lift facilities (gas lift) were installed on the four main field platforms. A continuous infill program has been in place since then until a temporary break was declared in early 2002.
In 1997, the size of the remaining targets was diminishing. If the infill program was to continue, it required a step change in the costs associated with new reservoir penetrations. The company had already successfully implemented TTD techniques (both CTD and TTRD) within the Prudhoe Bay field, Alaska. Therefore, a feasibility study was instigated to see if this technology could have an impact on the drilling costs in the Forties field.
The results were encouraging and suggested that there was a significant prize to be gained by implementing TTD in Forties. It also suggested that while TTRD could be implemented in the shorter term, there might be a larger prize if CTD capability could be introduced into the region. However, this conclusion is re-evaluated in some detail in this paper.
The decision was made to implement an initial program of four TTRD wells. This was to be done while the conventional infill program continued, so to ensure that the correct focus was maintained, an additional resource was allocated to the Forties drilling team to manage implementation of the TTRD technology. It was also agreed that the first part of the assignment was to spend 4 months in Alaska with the following agenda:
Learn about the practical aspects of TTRD.
Evaluate in more detail the potential of CTD.
The trip was invaluable in both regards.
Forties Generic TTRD Design.
Wells in the Forties field are highly productive. They are drilled to the required target, and the sail angle is maintained for reservoir penetration. This ranged from 25 to 65°. Water isolation was the major consideration, and liners were cemented in place and selectively perforated. The infill sidetrack program meant that the liner sizes varied among 4.5, 5.5, and 7 in. The completion strings were 5.5-in. tubing but with a 4.5-in. tailpipe and were designed for gas lift.
Despite injection support as the field was exploited, reservoir pressure had dropped by 200 to 500 psi. This meant that the biggest challenge for conventional sidetracks was managing the instability of the Balder/Sele shales that directly overlay the reservoir. Oil-based mud could not be used on the Forties rigs, and casing had to be set directly above the reservoir to ensure that the reservoir could be drilled and logged successfully. Attempts had been made to drill from above the reservoir to total depth (TD) in 8.5-in. hole, but this had proven more costly than a sidetrack drilled with two hole sections. For a slimhole TTD well, drilling a single hole section was the only option if a commercially productive well was to be delivered. Therefore, the plan was to sidetrack the motherbore from within the reservoir and build to and turn the well to reach the "attic" oil targets. This required build rates of up to 30°/100 ft, and a final inclination of approximately 100°. Again, the key consideration was water isolation, which meant that the liner had to be cemented and selectively perforated. Fig. 1 provides a schematic representation of the TTRD wells.
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