WELLBORE DAMAGE CONTROL: Drilling with water-base fluids in high-temperature wells
Extreme technical, logistical challenges off Africa
Michael Collins
Shell International
Nicholas Barnett
Gerald Woodgate
Halliburton
The Kudu field offshore Namibia, south-west Africa, was first drilled in the 1980s by a South African oil company known then as Soekor. When Soekor's interest shifted to the southeast coast of South Africa in the early 1990s, Shell picked up the block and drilled four appraisal wells to confirm the extent of the field. These wells were serviced from Walvis Bay, 900 km to the north. Workboat roundtrip transit times posed significant supply problems to the operation, and there were no plans to construct service facilities on the south-ern coast.
Decision to drill
In 2001, a decision was made to drill two additional wells. The first was undertaken to confirm the possible existence of another field to the north of the existing field. A successful well would trigger a significant drilling program in support of a floating liquid natural gas facility. The second well was planned to further test the existing Kudu field for potential local development, particularly the possible construction of a gas powered 400-Mw power station.
Because the expected arrival date for the first rig was late December 2001, contract award of major services had to be completed in record time. Proposals were invited in early September 2001, after which Halliburton Energy Services was awarded the drilling fluids, cementing, and logging contracts along with drilling tool supply. A top consideration in the award of contracts was the ability of the companies to mobilize equipment into Namibia and meet the fast-approaching December deadline.
The wells were drilled on paper and all proposed improvements to the design were tested. As noted above, the technical difficulty of the wells could have been comprehensively addressed using a synthetic-base fluid, but as this was not an option, the focus turned to formulating a water-base fluid that would meet the demanding criteria.
Extensive high temperature/static aging tests were performed on a variety of water-base formulations in the Aberdeen lab. The maximum temperature expected at this stage of planning was 185°C.
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After assessing the awarded rig's fluid handling capabilities, Shell and Baroid personnel recommended building a mud mixing plant to reduce rig time spent mixing new section fluids. Luderitz, a Namibian port city approximately 12 hours by boat from the Kudu drilling site, was chosen as the plant location. The Cape Town Baroid team completed an operational mud mixing plant and dry bulking system in time to meet drilling deadlines in January 2002.
Throughout both drilling operations, both plants operated smoothly, and there were no interruptions in delivery of dry and liquid materials to the rig.
Challenges
The team had approximately three months to test the Therma-Dril water-base system for drilling conditions anticipated on the Kudu N1 well. The 8 1/2-in. interval was a known high-temperature environment, and the drilling fluid would have to remain stable during long coring and logging intervals. The final formulation, determined by extensive lab testing and based on experience with field performance of various fluid types, was a system with glycol for shale stabilization.
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The drilling fluid recommended for the 12 1/4-in. interval was a KCl polymer system, also containing glycol for inhibition. A portion of this system would be mixed with the newly built high-temperature system at the outset of the 8 1/2-in. interval.
Due to high torque experienced at the outset of the coring operation, it was discovered that the inner barrel and core head had been left in the hole. The decision was made to log and cement the well, then kickoff above the fish.
Drilling the sidetrack
To ensure the desired drilling fluid properties would remain stable under the expected extreme bottomhole temperatures, extensive pilot testing was performed at the rig site, backed up by related testing at the Aberdeen lab. High-pressure, high-temperature fluid loss control additives were used. Any new mud built on the rig was formulated with drill water, as decreasing the KCl concentration improved polymer efficiency.
Electrical problems resulted in a two-day delay before sidetracking operations began. After two attempts to run a turbine, the well was kicked off with a mud motor and tri-cone bit. The active mud system was reconfigured from two to three pits to cool the mud for the mud motor. The riser was also boosted for cooling purposes. Both flowline and downhole circulating temperatures dropped by 5°C following these actions. The downhole temperature range was recorded at 98°C to 110°C while surface temperatures gradually rose from 45°C to 55°C.
High-temperature motor
After establishing the sidetrack, a high-temperature performance motor replaced the initial bottomhole assembly (BHA). Drilling operations were uneventful until the string parted three stands above the BHA at 4,747 m. After a successful fishing job, drilling resumed without incident, reaching TD at 5,275 m.
Prior to logging, part of the active system was treated for temperature stability, rheology and fluid loss, and spotted in the hole where it remained static for over 90 hours. As the logging interval was expected to last several days, an oxygen scavenger and a microbiocide were also added. When circulated to surface, the drilling fluid showed little degradation despite a bottomhole temperature of 210°C.
While drilling and logging the 8 1/2-in. sidetrack interval, there were no indications of sag, high temperature gellation, or deterioration of drilling fluid properties, even though parts of this section were open for over 70 days.
Success factors
Once it was determined that a water-base fluid must be used to drill the deep, high-temperature wells, the drilling fluids team launched a program of extensive pilot testing before and during the drilling operation. As a result, the water-base system was selected as the most appropriate for the expected conditions. Its stability was strenuously tested during the Kudu wells, and it proved itself to be a viable alternative where drilling with a synthetic-base fluid is not permitted.
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As noted earlier, it was anticipated that the bottomhole temperature would reach 185°C. As the well progressed, it became apparent that the downhole temperature would exceed this mark. The drilling fluid engineers performed daily pilot testing at the rig site in addition to carrying out their normal fluid supervision duties. Consequently they were able to take pro-active measures with the system to prevent any problems related to deterioration of drilling fluid properties.
Coordination among the project teams located in Norway, Cape Town, and Aberdeen also contributed to the success of the operation. Pers-onnel participated in daily morning meetings with the operator and service companies maintained active lines of communication among themselves. The liquid mud plant operators ensured that the drilling fluid was formulated correctly and shipped in a timely manner in the volumes required, saving rig time costs and minimizing rigsite treatment demands.
The second Shell Kudu well, drilled in June 2002, used the same drilling fluid program and is the fastest well drilled in the field to date. These wells are models for the safest and most efficient drilling practices for the area. The project also serves as an excellent guide for operators considering drilling start-ups in remote locations where facilities must be installed from the ground up.
