Teamwork, extensive preplanning pay off for Norwegian Sea well

July 3, 2000
The results of a wildcat well, located in the Voring Plateau of the Norwegian Sea, show that coordinated management and planning from the service company, drilling contractor, and operator can improve drilling performance over other regional wells.

The results of a wildcat well, located in the Voring Plateau of the Norwegian Sea, show that coordinated management and planning from the service company, drilling contractor, and operator can improve drilling performance over other regional wells.

In July 1999, Saga Petroleum AS completed the remote Gjallar wildcat in 1,352 m of water. Drilled vertically to 3,827 m, then directionally deepened to 4,103 m, the company selected the well location to test reservoirs within the top portion of the Cretaceous pay zone while avoiding any potential gas-chimney hazards.

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The main geological targets included the Springar sandstone in the Upper Cretaceous at 2,550 m RKB (rig kelly bushing) and the Nise prospect in the Intra Campanian (2,930 m RKB). This article presents selective technical processes, operations summaries, and some of the lessons learned from this well.

Hurdles

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Using both UK Western margins and Norwegian data drilled in the region prior to the Gjallar well (Figs. 1 and 2, Table 1), it became evident that prior operator experience in the area underwent drilling, equipment, and operating difficulties in the deep water, notably during the open-water phases (from spud to blowout preventer rig up) on the first few wells.

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Although these operators met the required safety and environmental performance levels, the data showed that operational lost time could have been better managed, controlled, or prevented, especially from the standpoint of wellbore and equipment issues. For example, eight deepwater wells using fourth-generation drilling rigs in the Norweigian Sea averaged 90 operational days to drill to TD, log, and abandon the wells.

On the other hand, the remote Gjallar well was finished in half the time of this average.

Scarabeo 5 upgrade

To meet the wellbore objectives, special considerations were needed to overcome the deepwater environment, equipment requirements, geohazardous conditions, and lack of familiarity and knowledge in such a remote wildcat area.

First of all, Saipem SPA's Scarabeo 5 semisubmersible, which was previously employed on subsea completions for 3.5 years, had yet to operate in deep water. Thus, the rig required full upgrades to the blowout preventer (BOP) and dynamic positioning systems along with personnel training.

Additionally, the rig was upgraded to withstand the extra loads involved in deep water and to manage an emergency provoked by a drift-off or drive-off situation.

Main modifications to the rig included:

  • An additional pair of double tensioners for a total of 16, each rated at 120,000 lb.
  • A Shaffer antirecoil system for emergency disconnects.
  • A new acoustic position reference system HiPAP integrated to the ADP 703 dynamic positioning system.
  • Installation of a new long base-line acoustic position reference system Simrad 418.

Additionally, the BOP upgrade included:

  • A new BOP control system with subsea multiplex (MUX) cable connection feature and retrievable pods.
  • Two sets of shear rams with an automatic shear package to boost the shearing capacity to 3,000 psi.
  • A BOP funnel for guideline-less and hydrate seal connection.
  • A wellbore pressure and temperature sensor.
  • A Seaflex riser management system for the control of optimum rig position while drilling, including a time-to-go module.
  • Maintenance of the full riser string including an inconel cladding for all choke and kill line boxes.

Data review

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Second, a review of regional deepwater drilling data conducted by Kingdom Drilling Services in 1995 and 1998 concluded it should be possible to accelerate the learning curve through the study of prior practices. From such studies, Figs. 3 and 4 derived that straight deepwater exploration wells encountered a significant amount of lost time-70% of which occurred during the open-water drilling phases.

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When further reviewed, this study concluded that 98% of these problems can be credited to three operational areas (Fig. 5): wellbore conditions (37%), waiting (36%), and equipment issues (22%).

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To tackle hazards identified from problems previously experienced, the following practices were put into place:

  • A strategy where clearly defined goals and objectives are defined.
  • The use of fit-for-purpose, risk, organizational, and resource management techniques to meet wellbore objectives.
  • Detailed planning that all personnel can "buy in to."
  • The proper implementation of drilling parameters and bottomhole assembly optimization techniques.
  • Coaching and training of rig-site personnel.
  • Maintaining expert field expertise and supervision.
  • Following "Best Practices" established from prior work.
  • Keeping planning and implementation issues simple.
  • Providing personnel with the necessary tools and procedures to get the job done safely and efficiently.
  • Following the philosophy, "Do it once, do it right."
  • Cultivating a learning organization.

Strategy at work

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By complying with the above list, potential lost time in the deep open water was controlled (Fig. 6), despite the fact that a prognosed 600-m layer of shallow ooze sedimentary sequence had never been drilled in the area (Box: Biogenic oozes). Prior to operations, detailed planning and risk analysis, conducted on a continual basis, identified the key hazards while providing a means to overcome problems (Table 2).

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For example, seven weekly meetings held by the "open-water group" prior to spud ensured all action points were "owned" by those responsible, and that operational strategies would be first discussed within the group, then agreed upon by consensus.

Furthermore, BHA and component design was derived from best field experience incorporating data acquisition and directional needs to meet wellbore and well engineering requirements. Best practices, such as the discontinuation of upward rotation and the initiation of sweeps to maintain the wellbore clean, were based on experiences gained and well data reviewed from drilling operations in the UK Western Atlantic margins, West Africa, and South Atlantic.

During execution, the ooze team leader maintained a permanent rig-site presence, working on a split rotation to ensure full 24-hr assistance was available for any issue that may come up. Additionally rig-site section training, coaching, and discussion meetings were conducted off tour.

Drilling strategy, deepwater lessons, contingency plans, and emergency procedures also used information taken from the best drilling practices. These issues were then discussed in detail as guided by senior drilling and service personnel to create the necessary awareness for all issues of concern.

Detailed final guidelines for each operational stage were then produced in consultation with operator, drilling-contractor, and service-company personnel to ensure that all essential considerations were fully understood and dealt with by those responsible. Such typical rig-site management was then maintained throughout the well by the Saga drilling supervisors.

Drilling and coring

The drilling procedures went as follows. After achieving a 1.17 sp gr leak off test, claystone formations with traces of tuff were drilled until a drilling break occurred at 2,323 m. At this time, the well was shut in. No pressures were observed and drilled gas peaked at 12%.

Drilling commenced and the mud weight was increased to 1.10 sp gr by 2,360 m. After reaching section TD at 2,384 m, a 150 l. trip-tank increase was noted. To stabilize the well, the mud weight was then increased to 1.13 sp gr. Unfortunately, the pressure-while-drilling tool failed at this point.

As the well had to be spudded north of the prognosed location, a result of transponder buoy array and positioning difficulties, a wellbore correction was required, increasing wellbore inclination to 10

A leak-off test of 1.26 sp gr was obtained after drilling out the 133/8-in. casing shoe. After an unplanned trip caused by the failure of the measurement-while-drilling tool, the 121/4-in. section was drilled in two milled-tooth rock bit runs using low bit weights and controlled penetration rates (< 40 m/hr) to accommodate sonic logging data requirements. As the well approached TD, penetration rates were reduced to 21 m/hr.

The mud weight varied from 1.16 to 1.20 sp gr in this section and was diluted with premix to maintain consistency. The crews observed excellent hole quality throughout the section with only intermittent overpulls of 50 tonnes on the drillstring, probably caused by ledges observed on trips to the shoe.

Pore pressure varied from 1.11 to 1.12 sp gr, dropping to 1.06 sp gr at the end of the section. The well direction and angle were maintained as required, dropping to near vertical at section TD. Additionally, a 21-m long core was cut from 2,554 to 2,575 m, using an 81/2-in. corehead to improve core recovery (99% recovery).

The core was cut in 5 hr at 60-85 rpm with a bit weight of 5 tonnes. The driller reduced penetration rates from 5 to 2 m/hr in the last 5 m before the core jammed. As the crews approached the 121/4-in. TD, it became evident that the expected plastic shales, as seen on other deepwater wells, were not present. Drilling optimization then reflected this.

After the cement and floats were drilled with a 81/2-in. milled-tooth bit, the driller applied penetration rates of 20 m/hr and bit weights up to 23 tonnes until a drilling break at the next core point (2,990 m) occurred. Coring proved difficult, however, with low penetration rates of 2.7 m/hr and corehead balling.

Core No. 2 was cut from 2,997 to 3,006.5 m, then jammed. Subsequently, penetration rates higher than prognosed were maintained to section TD, with no directional corrections required. This resulted in a final well inclination of 5

Further progress was affected by junk in the hole, bit damage, and uncertainty, resulting in more bit trips than probably required. A 6-m long TD core was cut from 4,097 to 4,103 m after which final TD for the well was reached, proceeded by 1 week of data acquisition.

Casing and cementing

The 30-in. conductor was run to section depth and reciprocated while circulating without difficulties. While pumping and displacing the cement, the crews observed good returns throughout the interval. The operator then utilized a Drill Quip Inc. "Titus system," a programmed top-up cementing procedure used as a precautionary measure once the conductor was set on bottom.

A final 3/4

During final displacement, however, returns were lost and the plug did not bump. A balanced plug was set to achieve the required casing pressure test where cement was squeezed through the shoe and float-after no cement was encountered while drilling through the floats.

Although the margin between the leak-off test and the mud weight was only 0.04 sp gr, the crews successfully ran, circulated, and cemented in the 133/8-in. casing string without losses or any problems. This raises an interesting point to consider when considering realized formation fracture gradients after drilling such sections.

After drillng the 12 1/4-in. section, the crews also ran the 896-m long, 95/8-in. liner and hanger in 14 hr at a depth of 2,854 m (1 m off bottom). The liner was cemented with no observed fluid losses.

Additionally, no shearing action occurred when the cement plug dart theoretically bumped the plug and no cement plug bump was achieved. When drilling out the shoe-track, however, cement was tagged 14 m above the shoe and the required casing test was achieved.

Mud engineering

The open-water sections were drilled with seawater and 6 to 10 cu m viscous pills pumped every 30 ft. The 17-in. hole section was then drilled with a diluted KCl system and an initial mud weight of 1.06 sp gr. The section proved unstable towards the end but was finally stabilized with a 1.13 sp gr mud weight. The section consisted mainly of claystone that had to be treated over the last 100 m.

In the 12 1/4 and 8 1/2-in. hole sections, a NaCl-KCl hydrate-inhibition system was used. With an initial weight of 1.17 sp gr, fluid density increased to 1.22 sp gr through slugging activities and infiltration of silt from the formations drilled. Desilters could only be run for short periods due to poor maintenance, and large amounts of premix were required to maintain the mud weight as desired.

Pore pressure for the section was evaluated as 1.11-1.12 sp gr, falling to 1.06 sp gr at the end of the section. The logged hole demonstrated an in-gauge and trouble-free borebore during drilling, tripping, and logging operations. The mud was readily maintained in the 81/2-in. section and was managed at 1.22-1.23 sp gr by running centrifuges, desilters, and premix additives (1.17 sp gr).

Again, no drilling, tripping, logging, or hole difficulties were experienced during any operational activity.

Data acquisition, P&A

A new remote-operated vehicle (ROV) operating system was integrated into the rig's subsea system using a back-up ROV maintained on board. ROV performance proved exceptional in this deepwater pilot project, achieved throughout the open-water drilling phases. This operation provided vital data acquisition with respect to time dating of the shallower sediments. No downtime resulted from any ROV operations.

Formation evaluation required a total of 12 days, 4.5 days more than planned while representing 20% of total well operating time.

During the plug-and-abandonment phase, a 81/2-in. Parabow cement retention device was set in open hole, retaining a 200 m cement plug set from 50 m below the 95/8-in. liner shoe. The well was displaced with 1.13 sp gr mud and a 133/8-in. bridge plug. Next, the casing was cut at 1,560 m and an additional plug was set at 1,425 m.

The BOP and 72 joints of riser were pulled in only 26 hr, with the ROV simultaneously retrieving marking buoys and transponders. The wellhead was initially cut 5 m below the seabed with a Weatherford MOST tool, but could not be pulled due either to an ineffective cut or because of a "car park" cement block occurring from the excessive pumping of cement.

A second run was made to cut shallower 3 m below seabed with jar and accelerator assembly. Experience demonstrated that sufficient time would be necessary to make the cut instead of working the pipe with high overpulls.

Gjallar performance

As Fig. 6 and Table 1 show, performance by the operator and drilling contractor on the Gjallar well significantly improved as compared to other deepwater wells drilled in the area. Additionally, the total downtime for Gjallar, at 180 hr (Table 2), was significantly less that both conventional and deepwater Norwegian wells.

It was evident, however, that by highlighting the lost time and identifying root causes, future periods of down time could be further controlled and mitigated. For example, even on the Gjallar well, equipment failure still dominated.

When compared to the UK Western margins, however, further improvements can still be delivered as shown by average operational days of 49 days for third-generation rigs and 33 days for fourth-generation. Thus, it is felt that a target of 30 days from spud to abandonment can become a realizable goal for future wells.

Acknowledgments

The authors thank all offshore personnel who contributed to this article.

The Authors

Flemming Stene is senior drilling advisor for Saga Petroleum, Stavanger. He has 16 years of experience in drilling technology, design, planning, and drilling operations. Stene has worked in deepwater projects since 1993 and worked as a senior well engineer on the Saga Gjallar project from initiation in 1995 until the well was completed. He holds a BS in mechanical engineering and petroleum engineering.

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Peter Aird is an independent drilling consultant with 22 years' field and office experience. He has worked in various deepwater projects since 1990, often consulting as a drilling team leader responsible for delivering the top and surface holes. Aird holds an HND in marine engineering and is currently completing a masters degree in drilling engineering at Robert Gordon's University, Aberdeen.

Gjallar lessons learned

The remote Gjallar well demonstrated that success rates typically achieved by more mature plays can be achieved in a wildcat situation. Onits frist attempt, the Gjallar well was completed under budget while meeting all required performance levels with acceptable down time, notably in the open-water phases.

Results show that:

  • Experience from the other deepwater wells and deepwater experts can be used to best effect.
  • Risk, organization, and resource management issues can be realistically viewed as essential to meeting wellbore objectives and performance targets.
  • Lost time can be controlled, managed, and prevented.
  • Operations should concentrate on the basic technical and commercial issues at hand.
  • Management of critical systems such as dynamic position, blowout preventer, and remote-operated vehicles contribute to the reduction of lost time.
  • Best practices used to drill the ooze sequence can result in trouble-free operations.
  • Lost time during final displacement of the 20-in. casing require a more detailed review.
  • Waterflow in the 17-in hole section was experienced and controlled by increased mud weight with no significant lost time.
  • No pressurized permeable zones were encountered.
  • Equipment failure dominated nonproductive time.
  • Drilling and bottomhole assembly performance was viewed as an essential area for improvement.
  • Plastic shale difficulties from other deepwater wells were not experienced on the Gjallar well.
  • TD cores should be used to optimize future bit performace in similar 8 1/2-in. sections.
  • Excess cement at the seabed can cause wellhead retrieval difficulties. Top-up cementation should only be used as a contingency.

Biogenic oozes

On the Gjallar well, biogenic oozes, the first to be encountered in this area, occurred about 150-750 m below the mud line. An understanding of the lithologic nature of this sediment type aided in designing the well program.

Oozes are derived from the settling of pelagic organisms (free swimming or floating) and contain more than 30% skeletal material. They can be either calcarceous (calcite, aragonite) or siliceous.

Distribution of this biogenic sediment depends upon the supply of skeletal material, dissolution of skeletons, and dilution by other sediments such as turbidites and hemipelagic clays. This means that the drilled sequence will exhibit varying physical properties, depending upon the distribution of the sediment.

Internal properties

Unconsolidated oozes are characterized by a high porosity. They may have a fair initial strength due to a web-like texture that often contain dissolution and cementation features. When disturbed, such oozes may produce excess pore water (like quicksand) and lose strength. This condition can be most noticeable in siliceous and coarse-grained calcareous oozes.

Compaction, dissolution, recementing, and diagentic effects may transform siliceous oozes into harder material. If the ooze remains uncemented, coarse-grained ooze layers may become mechanically weak like terrigeneous sands.

Hardgrounds and nodules may cause problems in terms of erratic bit impacts that could result in irregular hole shapes. If gas bearing (unlikely on the Gjallar well), such deposits could exhibit reduced grain density, as the sand grains can also be charged internally.

Geohazards

Highly permeable, friable layers of coarse-grained ooze could cause wellbore collapse, sand production, and lost circulation. Oozes overlain by slightly less permeable pelagic mud may be over-pressured as well.

Pore pressures encountered within the permeable and unconsolidated layers of the ooze, particularly when associated with gas, could represent a threat to well stability.

Collapse and pore-water release from disturbed ooze along the casing-cement-sediment interface may potentially result in piping and vertical fluid migration, allowing for pressure communication between permeable layers or to surface.