In February 1994 Shell Expro drilled an extended reach platform
well from the Tern field platform to a small hydrocarbon prospect
located five kilometres to the north of the platform. The well proved up the accumulation and has produced up to 18,000 barrels per day on extended production test.
The success of the well has increased confidence in long reach drilling capabilities and in the viability of developing small accumulations around existing facilities. Spurred on by the encouraging results, Shell's technical staff have been looking for similar opportunities around other mature fields. They have also been sharing their experience with the industry by means of a paper (SPE 28838 by Meertens, Van Der Harst and Kloss, European Petroleum Conference, October 1994) and more recently in a talk given by Rob Meertens to the SPE Aberdeen Section in May 1995.
New oil at the drilling limit
Rob introduced his presentation by commenting that this project started with the development group wanting to achieve a long reach oil strike. However, for the drilling group the main aspect was drilling to the limit. 'I hope that you will appreciate both aspects of this story and will share our conclusion that this success will lead to further opportunities in the North Sea and beyond,' he added. His presentation covered an introduction to Tern North, a discussion of the development options con-sidered, the well design, operations experience and general conclusions.
The Tern field
In 1977 the third exploration well on the Tern field found water with some oil shows in a fault block at the northern end of the structure. 'The well found a 'water-up-to' but did not penetrate the formation at its highest point. Geologists calculated that the attic oil in place was less than two million barrels. Development was not considered further, as the well was also in a different pressure regime from the Tern field and there were doubts about the oil migration path and charging,' Rob remarked. He then moved on to a revised structure map produced in 1993. 'What has happened? We've changed out the geologists, obviously!' he exclaimed. There had been a seismic review and a lot of new wells drilled in the main field. Refinement of depth/time conversion and extrapolation to the north led to a more optimistic estimate of 38 million barrels of stock tank oil initially in place (STOIIP) for the attic oil. Extensive use had been made of seismic amplitude anomaly analysis to identify hydrocarbon indicators and increase confidence that the updip volume was hydrocarbon bearing. There was sufficient justification to proceed further.
'The reservoir engineer was set to work and on the basis of a risked reserves analysis, he estimated that the producible hydrocarbon volume was in the range 0.3-20 million barrels with an expectation of two million stock tank barrels. This resulted in an expected NPV of �10-20 million, hardly enough to justify a project,' Rob said. The wide range of reserves estimates was due to uncertainty in the degree of communication and pressure support, ranging from a case with a single well and depletion drive in an isolated fault compartment to a case where the northern block would be a mere extension of the main field with good communication and three wells supported by gas lift and water injection.
Development options
A viable appraisal/development proposal therefore had to be robust against a dry well and against a small producible volume. The characteristics sought for the development options were low appraisal costs, supported by options to sidetrack into the main field. The three low cost appraisal/development schemes considered were extended reach drilling (ERD) from the Tern platform, a subsea satellite scheme and a floating production storage and offtake vessel (FPSO).
Rob summarised the respective merits and disadvantages as follows: 'For the subsea development and FPSO cases you drill the well from a floater and it is relatively inexpensive - approximately �3-4 million for the dry hole cost. But the difficulty starts with the production testing and development which has a high cost in these cases. By comparison, the ERD option involves a higher drilling and dry hole cost and higher risks during drilling but the development costs are very low indeed.' He highlighted the development cost comparison with the subsea option in particular: 'It is remarkable that our subsea costs for connecting a small accumulation to a platform are much higher than drilling a relatively difficult well to a very significant distance from the platform so that it is less expensive to reach such a location underground than along the sea bottom.'
A phased ERD approach was selected as the development option. 'We were not merely looking at the first fault block but also considering the possibility of sidetracking into other blocks without having to drill another well from a floater. Extended reach drilling offers a great benefit over the other options in this case. It also offers the advantages of much easier long-term testing and the possibility of sidetracking back into the main field if necessary,' he added.
Well design
In the ERD approach there is only one cost item: well expenditure (drilling, completion and platform flowline). As basic well costs are almost fixed by the total length of the well, the main threat to these costs comes from cost overruns due to underestimated drilling problems. The well design provides the best opportunity to mitigate these risks.
The main risks and requirements governing the well path design were identified as:
After reviewing experience on the Statfjord field where an ERD well had been successfully drilled with a 'double build' well design, this type of design was also adopted for Tern. The well path has a low inclination in the 17 1/2" hole and a further build to 82degrees in the 12 1/4" hole with a drop back to lower inclination in the vicinity of the target.
'This design has the disadvantages of a slightly greater total well length and a greater maximum inclination. Open hole logging at this inclination requires logging while drilling (LWD) or drillpipe conveyed electric line logging but the conventional design inclination is also beyond wireline serviceability,' Rob commented. 'The main advantages of this design are that drilling simulation showed a 15 per cent lower torque requirement than the conventional design and also that wireline serviceability would be possible to a greater depth - at about 7000 feet measured depth (6000 feet vertical depth) where the wellbore inclination reaches 70degrees.'
Managing the drilling risks at each stage with rigorous risk assessment were key to the success of the well. Rob gave an example of the risk assessment for poor hole cleaning in the 12 1/4" hole section. The potential impact would range from a reduced drilling rate to stuck pipe and a sidetrack. Risk mitigation measures were identified as use of large OD drill pipe, high drillstring rotation speed, circulation periods, close attention to mud properties or, as an alternative, an upgrade in mud pump capacity. Costs of the alternatives were estimated and appropriate measures were taken to reduce risks cost effectively to an acceptable level.
Operations
Well TA-05 was drilled from the Tern Alpha platform in early 1994. The 17 1/2" and 12 1/4" hole sections were drilled without significant problems. The 17 1/2" section was drilled with water-based mud to 6080 feet with a maximum inclination of 45degrees. The hole problems antici-pated in the 13,000 feet long 12 1/4" section did not materialise. This section was drilled with oil-based mud at around 800-900 feet per day and proper hole cleaning was maintained throughout. 'It was absolutely no problem and in particular the 21,000 ft lbs maximum torque measured was 25 per cent lower than we expected,' Rob said. Friction factors were in the range 0.10 to 0.18 instead of 0.15 to 0.25 previously used for modelling. Another parallel ERD well has now been drilled to Tern North and an even greater torque reduction has been observed. 'There is even more scope to go beyond the targets that we have achieved already,' he commented.
Rob then gave further details of the 12 1/4" hole cleaning measures:
Mud properties and condition
Drill string rotation speed
Large OD drillpipe
Circulation periods
Viscous pills
Drag charts
Wiper trips
Completion
The well was perforated with 41/2" TCP guns and completed with 51/2" tubing including gas lift mandrels as gas lift is available from the Tern facilities. Permanent downhole pressure and temperature gauges were also included to allow accurate decline analysis but unfortunately the gauges failed within 48 hours, possibly due to crushing of the gauge cable.
'The well was drilled and completed within 105 days. Including costs for wellhead equipment, tree, completion and flowlines, well costs were only about 50 per cent higher than those observed on conventional low deviation platform wells drilled to similar true vertical depths. This is remarkable and shows how well ERD wells can compete with conventional wells,' Rob concluded.
A lot more oil
He added that Shell's seismologists and geologists have been triggered into reviewing old maps and had found many small accumulations which could be viable with ERD. Given that the rig capabilities were not fully utilised in the case presented, Rob suggested using a 9-kilometre radius from existing facilities when looking for new ERD prospects.
Go after them, he encouraged.
Rob first discussed a conventional well path design case with a relatively shallow kick off and a smooth build up to maximum inclination. A long tangent section with an inclination of 74degrees would be required to reach the target at a 16,000 feet horizontal reach. 'This design gives the shortest possible well length and the minimum inclination but has the disadvantages of a long, high inclination 17 1/2" hole section and high torque requirements,' he noted.
A low rheology oil-based mud was used with a yield point of 12-18 lbf/100 ft2. Low gravity solids content was kept below 5.5 per cent throughout the section.
Drill string rotation was found to be essential for hole cleaning and the optimum speed was found to be 120 rpm.
To maintain adequate annular velocity this particular well had 6000 feet of 6 5/8" drillpipe and 10,500 feet of 5 1/2" drillpipe above an 8" bottom hole assembly. The final mud flowrate was 750 gallons per minute with 4200 psi pump pressure.
Circulation periods took place regularly to ensure that all the cuttings were being removed. These took place at maximum rpm and flowrate with observations of the shakers for 0.5-1 hour every stand. Circulating was longer after oriented sections and was increased up to double the time required to circulate bottoms up.
High viscosity, high weight pills had a significant effect during the build-up section but no effect in the tangent section.
Predicted string weights and off-bottom torque versus depth were monitored for deviations indicating a cuttings bed build-up.
Few wiper trips were required and there was no backreaming.
The 8 1/2" hole was drilled to a TD at 21,082 feet. Open hole data acquisition went as planned using LWD. A hydrocarbon column was encountered well within the agreed completion criteria and the section was cased with a 7" rotating liner. 'Two cased hole formation pressure tests confirmed a pressure differential in excess of 2000 psi relative to the Tern field thereby proving that this was a separate hydrocarbon accumulation,' Rob said.
When put on test the well rate stabilised at 18,000 barrels per day. After three months well production was declining very slowly indicating a large connected volume. Water cut had reached 15 per cent. Rob reported that the well was still producing a lot of oil but that water cut had now increased to 65 per cent. 'The well has been a full economic and technical success, has increased our confidence in ERD and has given us scope for significant new opportunities,' he said.
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