Project-based approach, cooperation push Stena drillship performance to ‘best in class’

Posted on 08 September 2010

By Mike Davis, Repsol; John Banks and Barry Rainnie, Stena Drilling

Figure 1: Stena Drilling’s sixth-generation drillship has an offline stand-building facility comprising its own equipment.

Figure 1: Stena Drilling’s sixth-generation drillship has an offline stand-building facility comprising its own equipment.

The challenges of bringing an enhanced deepwater drilling vessel design to market and into operations successfully in a high-activity market are immense. Using a project-based approach with close cooperation among the rig owners, shipyard, customer, third-party equipment suppliers and classification society, a sixth-generation drillship was engineered, built, commissioned and delivered on time. The drilling contractor teamed up with its client and completed its first two deepwater subsalt wells ahead of target time and without causing harm to personnel or the environment.

The drillship was delivered to the operator on 1 January 2008 in Korea, commencing a four-year contract.

This article will be a case study of the drillship’s HSE and operational performance on her first two ultra-deepwater subsalt wells in Brazil and the Gulf of Mexico (GOM). Progress of the project through the shipyard and acceptance programs will be detailed, and operational and HSE performance will be tracked though the rig’s first year of operations.

Addressed in the paper are the factors that contributed to the success of this project i.e. conceptual, construction and timely delivery, along with a top quartile drilling performance. The project based approach to operations and planning that led to exceptionally low rig non-productive time on start-up and excellent HSE performance throughout the first year of operations.


Searching for a shipyard to build a drillship as opposed to a semisubmersible was the first major hurdle as there were not many options available with the experience of building the size of vessel required. Yards in the Far East had greater experience, and a Korean shipyard was identified as the most promising prospect due to previous experience, suitable existing hull designs, yard capacity and work practices.

Figure 2: An overview of the drillship topside.

Figure 2: An overview of the drillship topside.

The shipyard had completed a series of four vessels, including three semisubmersibles and a drillship rated to 10,000-ft water depth during the late 1990s/2000. Because the drilling contractor required maintaining the same hydraulic drilling system that had proven successful on their previous builds, the basic 10,000-ft hull design previously built was selected as the most suitable. Using a basic standard-design hull minimized the design and engineering time for the build program and allowed a relatively early delivery schedule.

Based on the shipyard’s philosophy of building the vessels in blocks, on land, which are pre-outfitted, the vessel spent a minimum of time in the actual building dock. This enabled a delivery schedule of 18 months from steel cutting.

Choice of drilling equipment was guided by the desire to maintain continuity with the hydraulic ram systems installed on other rigs in the drilling contractor’s existing fleet. A similar philosophy was adopted for selection of the well control equipment; field-proven experience and compatibility with the existing fleet were the overriding factors.

The drilling and subsea packages were sourced as separate contracts from that of the shipyard. These contracts were taken over by the shipyard, making the overall vessel build contract a virtual turnkey contract, with the drilling contractor having limited responsibility in regards to increase of costs, weight and late delivery of equipment. This was a different scenario from previously built vessels where much of the drilling and subsea equipment was owner-furnished equipment (OFE). With no OFE, the unit was delivered complete ready to drill.

The shipyard contractor was responsible for the engineering design, procurement, construction, commissioning and completion of the systems integrity test (SIT).


Figure 3: The drillship’s dual mast arrangement.

Figure 3: The drillship’s dual mast arrangement.

The drillship was built to DNV class and complies with all Norwegian regulations. It is of DP class III standard, with three independent engine rooms, each containing two 7MW diesel Wartsila engines (six total) and equipped with six azimuth thrusters of 5.5MW each.

The drillship has a transit speed of 12 knots and fuel-carrying capacity of 11,500 cu m. The deck capacity is 20,000 mT, with large deck space and extensive storage capacities.

The hydraulic dual mast cylinder rig drilling package with separate offline makeup facilities for the drillship was designed and developed in Kristiansand, Norway.

The drilling contractor had more than 10 years of operating experience with the hydraulic cylinder hoisting rig package, which has proven to be a safe, efficient and reliable drilling system. The forward auxiliary tower has a lifting capacity of 600 tons (544 mT). For deepwater GOM wells, in terms of top-hole drilling, the auxiliary tower is predominantly used for drilling and casing while the main tower, with a lifting capacity of 1,000 tons (907 mT), is used to run the BOP on marine riser.

Separate from the drillfloor, the drillship has an offline stand-building facility comprising its own designated equipment (roughneck, catwalk, elevator, etc). The pipe racking in the setback is carried out by two off hydrarackers, both of which can feed main and auxiliary well centers. The setback area is recessed into the hull, allowing for 135-ft stands of drill pipe/triples of casing to be racked back for sizes 3 1/2 in. to 13 5/8 in.


Figure 4: The overall project S-curve.

Figure 4: The overall project S-curve.

The drilling contractor’s project team was established from in-house personnel and was limited in size based on the premise that senior operations personnel would join the build program six months to nine months prior to delivery. Additional members of the operations team were seconded to the project team for mechanical completion, commissioning and SIT.

An overall project manager and a dedicated topside project manager were supported by operations personnel chosen for their experience in each individual field, i.e. drilling, subsea, mechanical and electrical. To maintain continuity and experience, once the vessel became operational, the toolpusher, chief engineer, electronic technician and electrical supervisor rejoined the operations team and sailed out with the vessel on acceptance.

This philosophy has worked well in that the non-operational project personnel and the yard benefitted from the early stages of the project from hands-on operational input and the vessels benefitted in operation by having personnel onboard with an in-depth knowledge of the vessel and systems. In addition, the drilling contractor employed 12 Korean steel and coating inspectors who proved invaluable for their local knowledge and in-depth knowledge of the shipyard processes.

The policy of incorporating BOP service engineers into the core crew was continued from other drilling units with similar MUX control systems. The engineers were assigned to the project during the build and commissioning phases so their knowledge would be carried forward into operations. This provided immediate expert access for any problems, direct support from Houston on a 24/7 basis, maintenance planning and ensuring software is up to date. The drilling contractor also acquired drilling package service engineers to cover hydraulic and electrical disciplines to act in a similar way to BOP personnel – providing immediate follow-up to NPT situations and direct support from shore base.

Table 1: The drillship departed Korea on 5 January and arrived in Brazil by 25 February.

Table 1: The drillship departed Korea on 5 January and arrived in Brazil by 25 February.

Because a basic standard hull design was selected, the design and engineering process was restricted to installation of the drilling and subsea packages onto and into the hull design. This limited the amount of work required by the shipyard; therefore the time scale for the engineering phase of the project was reduced to meet the drilling contractor’s requirements. With the build schedule of 18 months from steel-cutting and the contract signed in late May 2005, there were only 10 months for detailed engineering, with four months prior to this for the conceptual design to be agreed.

The vessel was delivered on the due date with a change order overrun of less than 10% of the contract value.


As the vessel classification is Drill (N) and Ship-shaped Drilling Unit (N), all commissioning procedures were submitted to DNV for approval prior to commencement of the commissioning process.

Once the vessel reached an advanced stage, more operational personnel were seconded to the project team to undertake the mechanical completion checks along with shipyard quality assurance (QA) team. This benefitted both parties as the operational personnel walked the systems and built up a wealth of experience and SHI benefitted from having operational personnel point out to them where improvement could be made and system configurations were compared with operational reality. This was carried through to commissioning, where the operational team, in conjunction with shipyard/DNV/sub-contractor personnel, witnessed the commissioning process for each individual piece of equipment/system and signed off their acceptance of such and cleared of any deficiencies identified during the commissioning process.

Figure 5: The time-vs-depth curve for the rig’s first well, offshore Brazil.

Figure 5: The time-vs-depth curve for the rig’s first well, offshore Brazil.

Deficiencies identified during the build and commissioning were kept by the shipyard in their in-house data programs, which access available to the drilling contractor. Issues raised were officially taken to the shipyard, and the drilling contractor could check that they were logged in the database. The shipyard would call for inspections, and the team would visit the site with the shipyard QA to clear each issue. The shipyard would then update the data bank. This allowed the drilling contractor to ensure that the vessel was fit for purpose on delivery and would not take on significant work lists that would generate unnecessary pressure on operational personnel before the first well.

To fully test vessel functionality prior to acceptance, the drilling contractor reached an agreement with the shipyard for an enhanced SIT program to be undertaken on completion of commissioning. This agreement included a substantial financial settlement that the drilling contractor considered money well spent in terms of proving equipment usage prior to going onto location. This program was jointly prepared by both operations and projects and resulted in a 14-day simulation of all drilling functions while the vessel stayed on location offshore. The agreement was that drilling contractor personnel would operate both the vessel and the drilling and subsea equipment with limited supervision by the shipyard and limited assistance from the package suppliers.

This process gave the crew an opportunity to understand equipment functions and interaction and provided confidence in the design of the vessel and a security that she would operate as required in the field.

When the integration of the drilling systems began, a drilling foreman representing the operator was on site during SIT and signed off on each completed activity. A senior drilling engineer in Houston was also dedicated to the project.

The operator provided three key inspection companies for the integration testing program – a BOP specialist, a rig inspection specialist and a software/drilling equipment specialist. These specialists provided independent, third-party opinions on the integration testing process. The software/drilling equipment specialist provided exceptional support in helping to identify interface issues.

The operator participated in numerous factory acceptance testing (FAT) and commissioning activities. The acceptance criteria were set to a high standard, which contributed to the minimal NPT achieved during the first year of operation.


Table 2: The drillship’s lost-production time figures for the Brazil well.

Table 2: The drillship’s lost-production time figures for the Brazil well.

Key safety features incorporated during the drillship’s concept development stage included provision of a temporary refuge, port and starboard escape tunnels, and free-fall lifeboats.

To further reduce risks to personnel onboard and ensure a safe and healthy workplace, formal safety assessment (FSA) and working environment studies were performed through all phases of the design and construction of the vessel. The main FSA studies carried out included:

• Quantitative risk analysis of major hazards, such as blowouts, fires and explosions;

• Reliability and vulnerability assessments of safety critical systems;

• Hazard and operability studies of drilling, pipehandling, marine and utility systems;

• Emergency preparedness analysis; and

• Evacuation, escape and rescue assessments;

Occupational health issues addressed in the suite of working environment assessments included noise and vibration, illumination levels, material handling, chemical handling, means of access and human factors.

In addition, an environmental review was completed in support of the zero-discharge philosophy for the vessel.

An inspection and survey program was implemented to verify that the HSE objectives had been achieved. The program incorporated independent lifting equipment and dropped object surveys prior to drillship delivery.


The drillship left the shipyard on 5 January 2008 and arrived at anchorage off Rio de Janeiro on 25 February 2008. Table 1 provides a summary of the voyage.

Figure 6: The time-vs-depth curve for the GOM well.

Figure 6: The time-vs-depth curve for the GOM well.

Because commissioning was completed in the shipyard, good use was made of the transit to further familiarize the crew with the vessel systems and to provide extensive training on the company’s integrated management system for crew members new to the company. The management system incorporates the company’s management-of-risk tools, such as the permit to work system and lifting operations procedures, as well as rig-specific work methods for carrying out routine tasks onboard. The opportunity was also taken during the transit phase to develop a preliminary suite of risk assessments for these routine tasks.

Operations in Brazil came with its underlying challenges, including rig importation and regulatory standards.

Effective planning between operator and contractor was imperative to ensure a slick importation process. Pre-inspection audits were carried out in the shipyard to verify the conditions of all items that will be checked by federal environmental agency of Brazil (IBAMA) and the Navy of Brazil. Any non-compliance identified during the pre-inspection was pro-actively resolved during mobilization. The drilling contractor audit team onboard from Cape Town to Brazil verified compliance with Brazilian regulatory standards prior to eventual audits by regulatory authorities during the entry process.

The drillship sailed from Korea with a full two-year operating spares package and capital spares, ensuring maximum coverage for first well operations in Brazil. The drilling contractor invested heavily on capital spares. Fleet spares included equipment such as a top drive unit; complete BOP, including control system, hoist/tensioner/compensator cylinders, thruster units and drill strings.

Brazil, first well

The drillship arrived in Brazil on 25 February, and customs clearance and drilling license formalities took place until 16 March. The rig’s first well in Brazil was drilled by another operator in the Santos Basin. It had an AFE duration of 150 days. Challenges included:

• Deep water, 7,038 FT (RKB);

• Long, heavy casing strings;

• Deep salt sections.

Using dual activity, with offline stand-building and a separate torque-master unit, the drillship completed the first well ahead of AFE with no lost-time injuries.

Top-hole dual operations included:

• Drilling 36-in. hole using the Main WC while preparing/running 30-in. conductor on Aux WC.

• Drilling 26-in. hole using Main WC while preparing/running 20-in. casing on Aux WC.

• Running BOP on marine riser on completion of breaking down 26-in. BHA.

Table 3: The drillship’s lost-production time numbers for the GOM well.

Table 3: The drillship’s lost-production time numbers for the GOM well.

All drilling operations were carried out on the main well center while top-hole casing runs were carried out on the aux well center. The drillship’s stand-building facility and torque master machine allowed for drilling/casing and BHAs to be made up offline, separate from drill-floor operations on main and aux well centers.

The drillship’s lost production time for the first well was recorded as 125.5 hrs (4.32%) over a well duration of 121 days. Table 2 provides a summary.

On completion of the well on 17 July, the vessel back-loaded equipment and sailed to an anchorage location at Niteroi to export the vessel and commence installation and commissioning of a 6 5/8-in. fingerboard and belly-board for GOM operations. The drillship left Niteroi on 2 August 2008, arriving in the GOM 21 days later on 23 August.


The drillship started its second well (first well in the GOM) on 23 August. The AFE-estimated days for the exploration well in Keathley Canyon was 120. On arrival in the Gulf of Mexico, the vessel was inspected by the US Minerals Management Service. There was zero downtime due to regulatory inspections. Drilling challenges included:

• Deep Water, 7,025 FT (RKB);

• Long/heavy casing strings;

• Deep salt section;

• Ballooning and wellbore instability.

The operator’s approach to drilling its first deep sub-salt well in the GOM was to establish a small and experienced integrated drilling team. Two experienced senior engineers were brought in one year prior to spud and the superintendent brought in six months prior to spud. All three in-house staff reported to the drilling manager. Long-lead equipment was ordered nine to 12 months prior to spud based on a notional well design. Casing and wellhead equipment orders were based on a conservative well design.

Open communication with the G&G was paramount. A stage gate approach for the well-planning process with formal technical reviews was utilized as per the operator’s policy. But communication with the G&G team was enhanced to the point of daily discussions between drilling engineers and the G&G project team. Key well decisions were made with input from the entire team.

The vast majority of the rig crew had never worked in the GOM. Prior to arrival, the operator facilitated a “drill the well on paper” (DWOP) workshop, where each step of the well-construction process was analyzed in depth to generate ideas for improving performance and developing detailed plans for execution of the work. Plans of action were distributed daily to drilling contractors and key vendors. The drilling superintendent and drilling engineers went offshore to brief the crews on ballooning formations and drilling problems unique to the GOM. Time was spent explaining the differences between ballooning formations and a kick. There were no well control incidents on the well.

A given situation was risk assessed offshore when operational or logistical issues could not be resolved between the operator and drilling contractor. This process proved beneficial for all parties.

The well was completed on 3 February 2009, ahead of AFE with no lost-time injuries. (This time includes a bypass not discussed in this paper.)

During top-hole drilling, the drillship left the well site on two occasions due to hurricanes (Gustav and Ike), leading to more than 13 days WOW NPT for the well. The drillship’s ability to transit at 12 knots was valuable in terms of safety and operational planning during hurricane season. Following a formal risk assessment, the drilling contractor’s policy concerning the number of personnel allowed to remain on the rig during a hurricane evacuation was increased to expedite the start-up of work when the rig returned to the drill site.

All top-hole drilling and casing operations were conducted on the auxiliary well center. Running of the BOP on the main well center was hindered due to threat of hurricanes; therefore, minimum dual activity could be achieved. However, time savings during top hole were achieved with offline stand-building and the torque master machine in terms of offline makeup of drill pipe, landing string and BHA components.

The total NPT without WOW for this 29,000-ft, subsalt well in 6,900 ft of water was 12.2%. This well’s 309 ft/day penetration rate reflects top-quartile drilling performance compared with similar type wells in the Dodson Data System’s GOM drilling database.

The drillship’s loss-production time for the well was recorded as 106 hrs (4.5%) over a well duration of 98 days. A total of 63 hours of the drilling contractor’s lost-production time was associated with offloading riser that needed inspected at the end of the well. Excluding the riser issues, the rig had only 1.83% of loss-production time. Table 3 provides a summary of the departmental NPT.

The drillship also employs forward planners for well planning in conjunction with the operator’s drilling supervisors. The forward planner’s role includes:

• Plan, prepare and supervise all offline activities to maximize preparation done off the critical path (dual mast, stand building and torque master);

• Records operational performance data;

  • Key performance indicators;
  • Well analysis (NPT, online/offline hrs);
  • Tubular counts/inspections/rotating hrs;

• Complete well section after action reviews;

• Fingerboard management (to accommodate dual operations).


The strong HSE culture within the operator and contractor and the belief that all injuries are preventable paid dividends. At the time of writing, the drillship had completed 695 days in operation with no lost-time incidents, no restricted work cases and no pollution incidents.

The drillship’s operational utilization numbers for 2008 are provided in Figure 8. A lost-production time of 2.04% for the drillship’s first year in operation is a best-in-class achievement. Table 4 provides an overview of the 2008 lost-production time categorized under equipment.


The inherent challenges of deepwater operations across a wide range of environmental and general operational conditions are formidable. When these challenges are compounded by developing a new design and build program in a highly active market both for material resources and personnel, an integrated project management approach is required and demands close management and operational cooperations between the rig owner and the client throughout.

This project’s managed and operational planning approach to building and bringing a new deepwater drillship online and subsequently executing the first series of wells has paid off for both the operator and drilling contractor and has maximized the added value of the project for all parties involved.

Acknowledgment: The authors would like to thank the management of both Repsol and Stena Drilling for their support and approval in the writing of this paper.

IADC/SPE 128196, “First Year Performance Review for 6th-Generation Drillship,” was presented at the 2010 IADC/SPE Drilling Conference & Exhibition, New Orleans, La., 2–4 February.

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