The North Sea proved an overall success and has led the way for this pioneering technology to be applied around the world. This was the key message from Mike Tolstyko, senior well engineer for Shell Expro and project manager for the Tern 14 well, when he addressed a recent SPE dinner meeting in Aberdeen.

The concept for the multi-lateral Tern 14 well was first conceived in January 1995, and it was only after a careful and thorough planning phase that drilling commenced the following September. Mike explained that the well had several objectives: to appraise the Triassic a formation hitherto not produced by Shell in its Northern Business Unit which includes Tern; to convert the well into a gas-lift assisted oil producing well with two horizontal penetrations into the upper and lower reservoir sands (Upper Ness and Rannoch respectively) by means of a multi-lateral system; and to field test a multi-lateral system for future applications within Shell Expro.

Traditionally, Tern has an excellent producing reservoir in the Etive the primary development, he said. However, the Etive sands have been largely flushed with increasing amounts of water being produced, and we need to develop the poorer quality sands in the Rannoch and Upper Ness. Combining two producers in one offered obvious benefits.

The Tern 14 well was to be drilled close the crest of the reservoir in block 210/25a. When Shell's petroleum engineers identified the need for a multi-lateral well they specified certain functionalities which needed to be addressed in the design. For example, mechanical integrity at the junction point was seen as essential as the upper lateral kicks off in a shale formation. Selective isolation was required in the event that one of the laterals should in future water out and need to be isolated. The economics of the well could ride alone on the Rannoch producer so, at all costs, production from the lower lateral had to be guaranteed. Finally, there was a requirement for commingled (gas-lifted) production and isolation of the flushed Etive formation. In this instance, a hydraulic seal at the junction area was not considered necessary nor was selective re-entry into either lateral.

Considerable time was then spent by the well engineers in the planning stage reviewing certain areas critical to success. Casing wear was an item of out-standing importance in the combination 95/8" x 103/4" production casing which is subject to gas-lift pressure. Excellent cement jobs would also be required due to windows being milled in the 95/8" casing. In order to penetrate the Triassic formation, the production casing was required to be set through the Brent reservoir rather than above it as usual for Tern since the Brent and the Triassic formations could not be exposed at the same time for pressure reasons.

Added Mike: We knew there was a high differential pressure between the upper and lower reservoirs. Ideally we would have liked 81/2" lateral holes through the reservoir consolidated with a 7" liner to enable full LWD logs to be taken. While this was possible in penetrating the Triassic, it was not feasible in the horizontal laterals and we had to revise our designs and drill 6" boreholes through the objectives with the limited MWD systems available in that size giving us just gamma ray and resistivity information. And from a well control point of view, it was essential not to have communication between the laterals during drilling operations.

Mike explained that certain ground rules were laid down relating to the approach that would be taken throughout the project. In line with Shell Expro's other business units, the well engineering department within the Northern Business Unit had embraced fully the Drilling in the Nineties Philosophy and accordingly had set up long-term relationships with a drilling contractor and various sub-contractors, such as directional drillers, cementing companies, etc. While not wishing to break away from these long-term relationships, it was recognised that Tern 14 was not a routine well operation and so a dedicated project team was formed, headed by Mike Tolstyko. Apart from the core of Shell well engineers, it included petroleum engineers, representatives from the lead drilling contractor, directional drilling sub-contractor, and in this instance, the selected fishing and milling contractor. Under Drilling in the Nineties the responsibility to write the drilling programme is usually with the drilling contractor. However, due to the nature of the project incorporating such new technology, a decision was made in this case that the drilling programme would be written by Shell well engineering in-house. After having contributed to the programme, the drilling contractor was happy to execute the entire well on an incentive basis bearing out the excellent working relationship previously established.

The selected system was also developed in-house and a trial was held at the Bridge of Don test well facility to run through the basic planned operations, albeit at a much shallower depth than would be used in the well itself. A number of lessons were learnt and incorporated into the programme, Mike commented.

He went on to describe the execution steps leading up to the upper lateral including the Triassic producer and lower lateral reservoir entry. A 121/4" hole was drilled through the Brent formation for the first time on Tern. Despite experiencing overpressures in the region of 2000 psi, good drilling practices facilitated not only the drilling of the well itself but also logging it and then successfully cementing the 95/8" casing. The top section of this casing is 10 3/4" to accommodate the annular safety valves which Shell traditionally installs in its gas-lift producing wells. After drilling the 81/2" hole into the basement and encountering the Triassic, the team commenced a programme of extended production testing. Having achieved this, the next step was to abandon the Triassic and start work on the lower lateral which was viewed very much as a dry run for the upper lateral. Whilst retrieval of the whipstock from the lower lateral was not important, it was nevertheless attempted as retrieval from the upper lateral was seen as being crucial and the experience gained would be beneficial to the success of the entire system.

Risk assessments were performed before and during the operation. This turned out to be very valuable as disappointments on some aspects of the lower lateral were turned into successes for the upper well.

The plan for the lower lateral was to kick off from the 95/8" casing, through the top of the Brent reservoir and then to continue through the Rannoch formation. The intention was to drill the 81/2" hole section through the Etive, isolate this formation with a 7" liner, and then drill the 6" hole for a length of 1000 feet through the Rannoch formation. The information received from the pilot hole had provided a clear plan of the drilling path there was a window of only 18 feet through which to drill this 6" hole without traditional LWD materials.

However, the success of the entire project depended largely on being able to retrieve the 8" whipstock on which the window was milled. Before setting the 7" liner through the Etive, two unsuccessful attempts were made to retrieve the whipstock and replace it with a deflection tool which would facilitate running the liner in the lateral but was thought to be easier to recover than the whipstock. The problem was compounded by the inclination of the well being 45° and the orientation of the whipstock being on the low side of the well due to a requirement to build the well at high deviation rates some 8° per 100 feet drilled. Any prolonged attempts to recover the whipstock jeopardised the 500 feet of well which had already been drilled as several drilling assemblies had been necessary to reach the required inclination in the lower lateral. Doglegs in excess of 11° per 100 feet had actually been achieved.

A decision was made therefore to run and set the 7" liner with a conventional liner hanger/tie back packer at that point, leaving the whipstock in place. A 6" hole was drilled 1000 feet through the reservoir and lined with a 41/2" liner.

Using geo-steering methods we managed to keep the well in the reservoir for that 1000 feet, Mike said.

Based on the experiences of the lower lateral, Shell decided to use a smaller, 7" whipstock in the upper lateral, orientated 60° right of high side, which would be recovered immediately after the window had been milled in the 95/8" casing. And rather than rely on only one recovery method, a number of methods were now available. A step-by-step approach was taken so that if any part of the operation proved unsuccessful, recovery to still guarantee production of the lower reservoir was still possible. The whipstock was run and set in a permanent packer and after the window had been milled in the casing, the whipstock was recovered at the first attempt and a deflection tool was run to take its place. A precautionary milling run was made off the deflection tool to ensure that access through the window was still possible for subsequent drilling assemblies. Thereafter, 1500 feet of 81/2" hole were drilled through the shale and into the top of the reservoir. The 7" liner was run and set on bottom and cemented successfully. The liner had to be set on bottom as on top of the 7" liner was a guide sub, which required positioning very accurately some 15 feet above the top of the deflection tool.

Drilling into the Upper Ness ensued although not without its problems. A geological side-track proved necessary when an unexpected (sub-seismic) fault block was encountered in this section. The 41/2" liner was run to TD through the successful second sidetrack and perforated overbalanced after the liner had been displaced to Xanvis (a high gel brine to combat losses without impairing the formation).

Then came the more challenging job of constructing the junction itself. The 7" liner guide sub still protruded inside the 9 5/8" casing. Both the 7" liner stub and deflection tool were successfully removed following wash-over milling operations. The permanent packer which had formed the basis for the whipstock and the deflection tool was left in place and would be used later to accept the completion and facilitate the straddle of the junction area. The junction was thus constructed, leaving just the completion to be run. Once this had been achieved, the lower lateral was perforated through the completion using coiled tubing.

The Tern 14 well is currently being produced commingled from both legs. Initially oil production from the upper lateral flowed at around 800 cubic metres a day and the lowest formation produced at over 1200 cubic metres a day. Even though there was a differential in pressure between the Upper Ness and the Rannoch, the commingled production surprisingly achieved rates of around 1900 cubic metres a day. Today, the well is producing in excess of 1200 cubic metres a day.

Reviewing the critical success factors for the well, Mike highlighted the dedicated multi-discipline project team, allowing time and resources to plan, having a full understanding of the risk and concerns, and a positive and flexible approach taken by the contractor companies.

The success of Tern 14 has helped ensure a bright future for multi-lateral technology within Shell. Mike said that the Northern Business Unit had identified the need for 16 multi-lateral wells between now and the year 2000, and that multi-lateral wells is the number one technology challenge for the Shell Group worldwide.

Concluding, he added: Tern 14 was a fit-for-purpose multi-lateral and we can see future developments for this type of technology progressing to selective entry of the upper lateral and some kind of hydraulic seal being required around the junction area.

Based on the experiences of the lower lateral, Shell decided to use a smaller, 7" whipstock in the upper lateral, orientated 60° right of high side, which would be recovered immediately after the window had been milled in the 95/8" casing. And rather than rely on only one recovery method, a number of methods were now available. A step-by-step approach was taken so that if any part of the operation proved unsuccessful, recovery to still guarantee production of the lower reservoir was still possible. The whipstock was run and set in a permanent packer and after the window had been milled in the casing, the whipstock was recovered at the first attempt and a deflection tool was run to take its place. A precautionary milling run was made off the deflection tool to ensure that access through the window was still possible for subsequent drilling assemblies. Thereafter, 1500 feet of 81/2" hole were drilled through the shale and into the top of the reservoir. The 7" liner was run and set on bottom and cemented successfully. The liner had to be set on bottom as on top of the 7" liner was a guide sub, which required positioning very accurately some 15 feet above the top of the deflection tool.

Drilling into the Upper Ness ensued although not without its problems. A geological side-track proved necessary when an unexpected (sub-seismic) fault block was encountered in this section. The 41/2" liner was run to TD through the successful second sidetrack and perforated overbalanced after the liner had been displaced to Xanvis (a high gel brine to combat losses without impairing the formation).

Then came the more challenging job of constructing the junction itself. The 7" liner guide sub still protruded inside the 9 5/8" casing. Both the 7" liner stub and deflection tool were successfully removed following wash-over milling operations. The permanent packer which had formed the basis for the whipstock and the deflection tool was left in place and would be used later to accept the completion and facilitate the straddle of the junction area. The junction was thus constructed, leaving just the completion to be run. Once this had been achieved, the lower lateral was perforated through the completion using coiled tubing.

The Tern 14 well is currently being produced commingled from both legs. Initially oil production from the upper lateral flowed at around 800 cubic metres a day and the lowest formation produced at over 1200 cubic metres a day. Even though there was a differential in pressure between the Upper Ness and the Rannoch, the commingled production surprisingly achieved rates of around 1900 cubic metres a day. Today, the well is producing in excess of 1200 cubic metres a day.

Reviewing the critical success factors for the well, Mike highlighted the dedicated multi-discipline project team, allowing time and resources to plan, having a full understanding of the risk and concerns, and a positive and flexible approach taken by the contractor companies.

The success of Tern 14 has helped ensure a bright future for multi-lateral technology within Shell. Mike said that the Northern Business Unit had identified the need for 16 multi-lateral wells between now and the year 2000, and that multi-lateral wells is the number one technology challenge for the Shell Group worldwide.

Concluding, he added: Tern 14 was a fit-for-purpose multi-lateral and we can see future developments for this type of technology progressing to selective entry of the upper lateral and some kind of hydraulic seal being required around the junction area.

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