Record HPHT Norwegian well drilled with MPD flow detection and control

S.K. NAESHEIM, FRODE LEFDAL, and TOR ØYVIND OFTEDAL, BG NORGE; and HENRIK SVEINALL, Weatherford International Ltd.

The Mandarin East well exhibited the most extreme temperature and pressure ever encountered while drilling a Norwegian well. Planning for this exploratory well had anticipated a surface pressure of nearly 15,000 psi and extremely high temperatures. To understand and control wellbore dynamics while maintaining an overbalanced wellbore, operator BG Norge installed a managed pressure drilling (MPD) system to provide early kick detection and allow for wellbore breathing mitigation.

A key objective of using MPD was to set the 9 7/8-in. production casing shoe as close to the reservoir as possible, to allow the optimal 8½-in. section to be drilled to TD within a very narrow (0.4-ppg) drilling window. Well breathing events presented a significant challenge in this difficult wellbore environment, which made pore pressure evaluation and kick detection critical to drilling.

Using the service company’s automated MPD system to mitigate drilling hazards allowed the entire 8½-in. section to be drilled to 5,933 m (19,465 ft) TD. The system saved an estimated 10 rig days and $7.5 million, while reducing risk and improving safety. Controlling gas influxes and precisely weighting up the mud system saved five of those days when compared to a conventional system.

PLANNING THE WELL

Once the constant bottomhole pressure (CBHP) methodology was selected, rigorous planning and preparation were initiated. Prior MPD operations in Norway were drilled while maintaining a statically underbalanced mud weight. Annular friction and surface backpressure were used to maintain bottomhole pressure above the pore pressure. These existing procedures could not be applied directly to the Mandarin East well. Maintenance of an overbalanced mud weight limited the operational envelope to an extent, but the extreme HPHT environment prompted a cautious approach.

A project team of operator and MPD personnel was established four months ahead of the spud date. A rig survey determined that major rig modifications were required, because the area between the rig’s annular preventer and diverter couldn’t accommodate the rotating control device (RCD). Thus, the riser had to be nippled down in the yard, and a new, shorter, overshot mandrel and packer assembly were manufactured to provide the necessary space between the annular and diverter.

Most of the existing MPD procedures had to be modified, because underbalanced drilling (UBD) techniques could not be applied at any stage, and surface backpressure would only be applied if an influx was detected. It was necessary to include the MPD procedures in the conventional HPHT procedures and establish guidelines for the use of MPD and conventional rig equipment. Several workshops and HPHT training sessions were conduced for rig and MPD personnel.

A full suite of integrated procedures and decision trees was prepared. It was decided that any kicks above 1 bbl would be handled by the standard rig equipment, due to a risk of taking a secondary kick, if a kick greater than 1 bbl was circulated undetected to the surface, Fig. 1. The training, risk assessments, workshops and discussions with the crews prior to spudding were a very important factor in the success of applying MPD techniques.

Fig. 1. Conventional well control or MPD methods? This decision tree describes the path to making that call for engineers drilling an extreme HPHT well offshore Norway.

MPD RIG-UP

Two rig surveys were conducted to determine where the MPD equipment would be placed. Due to limitations on variable deck load, space and overshot mandrel modifications, none of the MPD equipment could be rigged up before the intermediate 13 5/8-in. casing had been run and cemented in place. Norwegian regulations also specified that electric cabling on the rig must be upgraded to NORSOK standards. A total of 2 km (1¼ mi) of new cables had to be put in place before the equipment could be installed.

The MPD equipment package featured an MPD manifold unit that included computer-controlled chokes, Coriolis flowmeters and an Intelligent Control Unit. A passive, self-lubricating, large-bore RCD (able to handle pipe up to 6 5/8-in. OD) was connected to the BOP annular. A removable bearing assembly for the RCD allowed for an 18.69-in. ID when the bearing was removed. The RCD model used is the first certified to API 16D specification. Its pressure rating is 2,000 psi static and 500 psi at 200 rpm, Fig. 2.

Fig. 2. The MPD package, including a choke manifold, Coriolis flowmeter, intelligent control unit and a rotating control device.

The equipment package also included various MPD sensors in the flowlines and mud pits. Hard, flexible piping was used to connect the MPD equipment to the RCD, the rig’s choke manifold, the trip tank and the rig’s poor-boy degasser. A top flange tied the RCD back to the rig’s bell nipple. This equipment was rigged up prior to drilling out of the 13 5/8-in. casing. About four days were lost, because of rig space limitations that required installation of MPD equipment after intermediate casing was landed.

DRILLING THE SECTION

An extensive flushing, pressure testing and fingerprinting program was conducted prior to drilling out of the 13 5/8-in. casing. The MPD system was engaged for the bottom 600 m (1,969 ft) of the 12¼-in. hole to acquaint crews with new procedures and equipment in advance of the lower, more difficult section.

Before drilling out of the 9 7/8 x 10 ¾-in. production casing, the 17.5-ppg OBM used for drilling out the cement and floats was fingerprinted again. At 5,407 m (17,740 ft), a LOT to 19.5 ppg was obtained. Drilling continued toward the reservoir at about 5,590 m (18,340 ft) with a 17.5-ppg mud weight circulating through the MPD system. Background gas (BG) was moderate, with levels of about 1%. From approximately 5,555 m to 5,560 m (18,225 to 18,241 ft), a gradual 1-to-5% increase in BG levels was experienced. Two flow checks were negative. At 5,562 m (18,248 ft), a sudden 10% increase in the gas level was observed. Drilling was stopped, and the well was circulated without any significant decrease in gas levels.

Surface backpressure (SBP) was added in 100-psi increments until the gas flow stopped. The flow and density parameters stabilized at 350 psi SBP, indicating a pore pressure of 18.5-18.6 ppg. To verify an underbalanced state, the MPD choke was opened briefly. The bottom-up gas was about 33%, and underbalanced conditions were confirmed.

The bit was held stationary at 5,562 m (18,248 ft), and the mud weight was increased from 17.5 ppg to 18.0 ppg in one circulation cycle, to slowly reduce the SBP on the MPD system to an equivalent 18.6-ppg dynamic mud weight. To confirm that formation integrity had not changed at the casing shoe (19.5 ppg), the MPD equipment was used to perform an open hole leak-off test. The 19.1-ppg test figure indicated that the pore-pressure/fracture gradient window had been reduced to only 0.5 ppg. Mud weight was ramped up to 18.2, 18.3, 18.4 and 18.6 ppg to carefully maintain a bottom hole circulating pressure less than 19.0 ppg, ensuring a 0.1 ppg safety margin, Fig. 3.

Fig. 3. Surface backpressure (SBP) (white line) was increased until fracture pressure was reduced, compared to the original test. Once the SBP reached 500 psi, the red line diverged from the blue line. The blue line shows that fluid was injected into the formation and that the leak off pressure was identified. Once SBP is removed, the well returns to a normal state with no losses or gains.

Total rig time was only 40 hr from the initial small gas influx at 5,562 m (18,248 ft) through a sequence of steps that accurately determined the pore pressure (at 18.6 ppg) with full pressure control, weighted up from 17.5 ppg to 18.6 ppg, and accurately determined the new formation integrity. Handled conventionally, the process might have taken 5 to 6 days. Keeping ECD below 19.0 ppg required that the flowrate be maintained below 200 gpm for the remainder of the well. Small losses were experienced through the sandy intervals.

After the gas incident had been resolved, confidence in the system increased. It was decided to apply SBP on connection, to reduce wellbore breathing and time required to circulate the gas out of hole. The available pressure window did not allow for a trip margin when pulling the BHA for bit changes and coring. Swabbing the well was avoided by stripping out pipe through the RCD with a backpressure equivalent to 19.0 ppg from TD to approximately 1,400 m (4,593 ft) inside the production casing. A heavy, 20.0-ppg mud cap pill was placed at 4,000 m (13,123 ft) to give the necessary margin for the rest of the trip. While tripping back in, the pill had not strung out much in the wellbore, and it had to be circulated out in steps, very carefully, to avoid losses. Although some losses were experienced, they decreased toward the bottom of the pill and completely stopped once the pill was out of the hole.

Extensive use of the MPD system and the application of new techniques for tripping enabled the  8½-in. hole to reach TD at 5,932 m (19,463 ft) in 8 to 10 days sooner than offset wells, where an intermediate liner was required. The 8½-in. hole size benefited wireline logging, coring, fishing operations and DST testing, compared to carrying out the same operations in a 6-in. or 55/8-in. hole. The MPD stripping technique was much faster than the standard process. It saved an estimated, minimum 12 hr on every trip.

The MPD operations were also used in the well's P&A phase. Common experience is that placing balanced cement plugs at almost 6,000 m (19,685 ft) is very difficult; often no plug is found when running in to tag. On the Mandarin East well, with a solid float in the cement string, the MPD system was used to hold roughly 50-psi backpressure on the plugs when pulling out of the cement. This kept the plugs in place, and, in fact, all the deep plugs were tagged on the first attempt. In addition, the 2,000-psi static pressure rating of the equipment allowed its use to pressure-test the cement plugs after tagging.

COST SAVINGS

Using MPD led to significant operational and economic advantages. In total, using the MPD system saved 18.5 days or about $13.9 MM. Less the time for MPD rig-up and testing the net savings were 10 days and about $7.5 MM.

Four days, or about $3.0 MM, were saved compared to a conventional set-up when controlling gas influxes, determining the pore pressure and enabling controlled weighting up. About tens days ($7.5 MM) were saved by successfully drilling the 8½-in. hole to TD in the narrow pore pressure/fracture gradient margin. The elimination of gas check trips when pulling out for bit changes and coring saved 2 days ($1.5 MM) The MPD system allowed stripping out with backpressure to control swabbing. Other savings include two days, because no dummy connections were required, and a half-day from conducting open hole LOT’s and pressure tests of cement plugs.

Time savings were achieved by locking in the ECD pressure during connections, which totally eliminated long circulation periods. However, this is difficult to quantify and is not included in the time calculation. A total of 8.5 days was spent on critical rig time for rigging up, flushing, pressure testing, fingerprinting and carrying out a full-scale drill.

OPERATIONAL ADVANTAGES

Using MPD and sophisticated flow detection equipment allowed the well to be safely drilled to TD in an 8½ in. hole with a 0.4-ppg pressure window. Doing so added significant value to the formation evaluation program, and in case of a DST.

The MPD system accurately determined the pore pressure in the well without the need for any wireline tools, including a sudden rise in pore pressure from 17.5 to 18.6 ppg. Locking in the ECD pressure during connections in a controlled, safe way eliminated all extra circulation time resulting from gas from wellbore breathing during connections.

MPD procedures can be tailored for the application and can be used to save time and cost, even when UBD is not required. Using MPD-controlled stripping techniques can eliminate the need for the conventional “pump out to the shoe” check trip. The MPD flowlines on this extreme HPHT well raised crew confidence, because gas was not escaping at the bell nipple on every bottom’s-up.

An advanced MPD flow detection device successfully detected an influx/loss of less than ¼ bbl. The faith gained in the MPD flow detection equipment eliminated the need for dummy connections normally used when drilling HPHT wells.

Lessons learned included the importance of a line large enough to avoid excessive backpressure, when large gas volumes are circulated through the rig’s poor boy system. Experience also illustrated that it is essential to minimize off-center drill pipe versus the rotary table. Misalignment of more than 2 in. could lead to time-consuming problems to install an RCD sleeve or bearing. So that the ECD pressure can be accurately locked in during connections the system should use a 2-in., 5,000-psi line from the rig stand pipe to the MPD choke manifold.

The MPD flowlines should also be tied in with the rig’s trip tank system. This allows circulation across the wellhead using the trip tank system with the RCD element installed. A 2-in. NRV should be installed in the line.

CONCLUSION

The change to a closed-loop, MPD system provided the data and control to drill within a very narrow window in this extreme wellbore and still maintain an overbalanced mud weight throughout the operation. Understanding pore pressure and well dynamics provided information for an automated control system using annular backpressure to effectively manage small influxes and losses. This capability allowed the well to reach TD with the optimal hole diameter. 

AUTHORS
	SIGVE KROHN NAESHEIM is wells project manager for the Knarr Development with BG Group in Norway. He has more than 30 years of experience, in various positions onshore and offshore, with both drilling contractors and major operators. His experience covers Europe, the U.S., South America, the Middle East and Southeast Asia. He holds an MS degree in petroleum engineering from University of Stavanger.
	FRODE LEFDAL is well engineering manager for BG Group in Norway. He holds an MS degree in petroleum engineering from Norwegian University of Science and Technology. He has 15 years of industry experience with major operators, working in Europe and South America. He is BG’s Subject Matter Expert for managed pressure drilling.
	TOR ØYVIND OFTEDAL is chief well engineering manager for BG. He is a petroleum engineer from Rogaland University and has 32 years of experience with the following companies: Phillips Petroleum, Saga Petroleum, Norsk Hydro, ConocoPhillips and BG. He has held engineering positions in: platform/pipeline inspections, drilling and workovers, well intervention and platform operations in Norway, Denmark and UK. He has been a manager/supervisor since 1986.
	HENRIK SVEINALL is the Product and Service Line manager for Weatherford’s Secure Drilling Services in Norway. He started his career with Weatherford as a UBD trainee engineer, and has worked as an engineer and project manager on UBD and MPD applications in North America, continental Europe and offshore in the North Sea. He holds an MS degree in petroleum engineering from University of Stavanger.