The report of the Outer Continental Shelf Safety Oversight Board, which was established following the Macondo blowout, provides recommendations to strengthen permitting, inspections, enforcement and environmental stewardship. The findings and recommendations provide a framework to build on reforms to create more accountability, efficiency and effectiveness in the Interior agencies. The recommendations address both short- and long-term efforts that complement other ongoing reports and reviews, such as Secretary Salazar’s 27 May report to the president, the presidential inquiry into the spill and the US Coast Guard-Interior investigation into the causes of the incident.

The recommendations range from improved consistency and communication of BOEM’s operational policies to technology improvements and day-to-day management in the field. Strengthening inspections and enforcement – from personnel training to the deterrent effect of fines and civil penalties – is a major focus of the recommendations.

BOEM director Michael Bromwich announced today the agency has developed an implementation plan for the recommendations, many of which are already under way or planned.

The plan outlines the initiatives and programs that the agency is undertaking to address the report’s recommendations. This includes reorganizing the MMS to address conflicts between resource management, safety and environmental oversight and enforcement, and revenue collection responsibilities; seeking additional resources in the form of funding, personnel, equipment and information systems; ethics reforms that include the establishment of an investigations and review unit and a new recusal policy to address potential conflicts of interests within BOEM and industry; and inter-agency coordination with federal agencies related to oil spill response and the mitigation of environmental effects of offshore energy development.

Secretary Salazar commented: “The report is what I was looking for: It is honest; it doesn’t sugarcoat challenges we know are there; it provides a blueprint for solving them; and it shows that we are on precisely the right track with our reform agenda.”

Director Bromwich noted that the initiatives are consistent with the reform agenda he has been developing and implementing. “Many of the board’s recommendations will be addressed through initiatives and programs that are already in process and are central to our reform agenda,” he said.

Map of Chevron concessions in Liberia.

Chevron has been granted approval by the Liberian government to acquire a 70% interest and operatorship in three deepwater concessions in Liberia. The deepwater blocks, LB-11, LB-12 and LB-14, are located between 12 miles to 110 miles (20 km to 180 km) south of the capital of Monrovia and cover a combined area of 3,700 sq miles (9,600 sq km). Under the agreement, Chevron’s Liberian subsidiary will conduct a three-year exploratory program that is expected to begin in Q4 2010.

“We are very pleased to participate in Liberia’s emerging energy sector,” said Chevron vice chairman George Kirkland.  “Entry into this large prospective offshore area allows us to advance our growth strategy for the region.”

“These licenses are on trend with new deepwater Cretaceous discoveries in the region and will expand our exploration portfolio in offshore West Africa, which has delivered significant production from several basins,” said Ali Moshiri, president, Chevron Africa and Latin America Exploration and Production.

In Africa, Chevron participates in exploration and production activities in Angola, Chad, the Democratic Republic of the Congo, Nigeria and the Republic of the Congo. Chevron produced a net average of more than 430,000 bbl of oil equivalent in 2009 in these countries.

Image courtesy of www.marathon.com

Marathon Oil’s Droshky development in the deepwater Gulf of Mexico began operations on time and under budget on 15 July and has since ramped up production to approximately 45,000 net bbl/day of oil equivalent, consisting of approximately 39,000 bbl/day of liquid hydrocarbons and 39 million cu ft/day of natural gas.

The Droshky development consists of four wells tied back to the third-party Bullwinkle platform. Three of the four wells are producing at better-than-projected levels, while production from the fourth well has been delayed due to an equipment issue. Marathon plans to re-enter the fourth well in Q1 2011 to make the necessary repairs.

“The Droshky field is performing well with good reservoir quality,” said Dave Roberts, Marathon’s executive vice president, Upstream. “Droshky is a successful development that is contributing significant, profitable production and value to Marathon’s Upstream portfolio.”

Marathon expects Droshky to produce at a peak rate of approximately 45,000 net bbl/day of oil equivalent, down from the original estimate of approximately 50,000 net bbl/day of oil equivalent. The additional work on the fourth well is expected to add approximately $25 million to the total project cost.

Droshky is located in approximately 3,000 ft of water in Green Canyon Block 244, about 160 miles southwest of New Orleans.

Image courtesy of www.prideinternational.com

Pride International has reached agreement with BP to amend the contract for the Deep Ocean Ascension to provide for a special standby dayrate prior to the startup of the previously agreed five-year term. The Ascension, the first of four new drillships in Pride’s ultra-deepwater expansion, is currently in the Gulf of Mexico undergoing integrated acceptance testing with BP.

The special standby dayrate of $360,000 became effective 23 August 2010 and gives consideration to the existing drilling moratorium in the US Gulf of Mexico. This dayrate will remain in effect until 1 April 2011 or the date the rig begins mobilization to its first drilling site, either within or outside the US Gulf of Mexico. The rig will then begin earning the applicable dayrate as defined in the existing contract for the five-year term, which was unchanged by the amendment.

Pride is working with BP to find a suitable drilling location in the operator’s worldwide portfolio.

Image courtesy of www.nauticalpetroleum.com

The Kraken appraisal well, 9/02b-4, on block 9/2b in the UK Central North Sea has been drilled to 4,502 ft MD, Nautical Petroleum announced today. The top of the target Heimdal III was encountered at 3,856 ft, with a gross thickness of 160 ft. The well proved a substantially thicker and higher porosity main Heimdal Unit III reservoir than expected.

Preliminary log evaluation indicates that the Heimdal III main sand contains 83 ft of net oil pay with an average porosity of 38.8% and an average oil saturation of 87.2%. No oil-water contact was encountered in the Heimdal III main sand; thus the Kraken Field oil-down-to (ODT) has been extended to a depth of 3,934 ft TVDss (1,199 m TVDss) from 3,842 ft TVDss (1,171 m TVDss) indicated in the 9/02b-2 well.

Upon completion of wireline logging, a 9 5/8-in. casing string was run and a 50-ft interval was perforated. A test string consisting of sand screens and an electric submersible pump was run, and the well was production tested. The testing programme was designed to recover uncontaminated reservoir fluid samples and to confirm the productivity of the reservoir tested in the discovery well, 9/02-1A. These objectives have been met, although operational problems caused by the exceptional quality of the reservoir encountered meant that it was not possible to flow the well at a stable production rate.

The well was initially pumped at a restricted rate of 300 bbl/day. A productivity index of 2 bpd/psi was indicated during this flow period, confirming the excellent multi-Darcy quality of the reservoir. Subsequent to this flow period, the productivity declined markedly. An injectivity test was completed, which showed an injectivity index of approximately 2 bpd/psi. This indicated that the productivity decline was due to the plugging of the sand screens rather than a reservoir or oil quality issue.

The well was thereafter produced at low rate to recover oil fluid samples, which will be used for development studies.  Preliminary analysis indicates an in-situ oil viscosity of c.100 centipoise, similar to that seen in the 9/02b-2 well.

The lower section of the well will be abandoned, and the 9/02b-4z exploration sidetrack will be drilled to a target west of the 9/02b-4 well. The sidetrack is expected to take approximately 14 days.

Nautical’s joint venture partner Canamens North Sea Energy had previously announced that it would not participate in the 9/02b-4 well; therefore Nautical will hold 70% interest and Celtic Oil will hold 30% interest in that well. Additionally, Celtic Oil will not partake in the 9/02b-4z exploration sidetrack. As such, Nautical’s participation in this activity is 100%.

Image courtesy of www.circleoil.net

Circle Oil has commenced its Morocco drilling program after repairing access roads that had been damaged by winter flooding. The rig has begun drilling at the first well site in the Sebou Permit. The first well, KAB-1, is planned to be drilled to a Miocene Guebbas Sand target, with an anticipated TD at 1,360 m.

This and each subsequent well in this five-well campaign is expected to take five to six weeks per well to drill. All wells are targeting Miocene aged gas sand targets varying in depth from 900 m to 1,700 m.

As part of this campaign the DRJ-6 well, drilled in 2009, is scheduled to be re-entered and tested.

The company also provided an update this week on its Oman projects. In Block 49, the 3D seismic acquisition survey (900 sq km) has been completed along with a 2D tie line of approximately 130 km between nearby wells. The field data is being transferred for processing, and this will be followed by comprehensive interpretation in the company’s offices in the UK and Oman.

Early interpretations of the field data have indicated the potential presence of the Ara salt formation, a major productive interval in adjacent areas of southern Oman.

In Block 52, a 2D marine seismic acquisition contract has been awarded and signed with BGP Oil & Gas Services.  The vessel, BGP Challenger, will acquire 5,000 km of 2D data to assist in firming up the prospect inventory within the block and is expected to undertake the survey in the latter part of Q4 this year, with field operations scheduled to be completed before year-end.

Figure 1: the main MMC interface.

Drillfloor equipment controls and associated equipment on the latest generation of floating drilling vessels have evolved into a “system” of computer-controlled machines that are currently operated by multiple operators each running these machines from a series of dedicated control stations. The latest drilling vessels use as many as three operator stations to drill the well, trip tubulars or perform offline activities such as stand building. These stations individually control their respective machines but require constant “multitasking” operations by their operators, which results in inefficiency and operator fatigue.

A multi-machine control (MMC) system for automatic control of the hoisting, rotating and pipehandling systems has been executed on a recently delivered sixth-generation semi. The MMC allows full automatic control of these systems from one operator using one joystick.

This article will discuss the control system and machine hardware and software and how the development process has taken this technology from concept to a working drilling and tripping machine that adds value, efficiency and safety.

INTRODUCTION

The latest-generation drilling vessels are employing more and more computer-controlled tools on drill floor. By replacing roughnecks with machines in hazardous areas, safety is improved for the crew. The increased number of tools does have its price, however. Several multitasking operations are required by the operators, where fatigue and loss of concentration can lead to dangerous situations even though preventive safeguards are in place.

Another issue introduced by the increasing number of machines is time consumption. This is especially noticeable considering that each pipe handshake takes time, with the operator having to switch between several machines.

Figure 2: The Maersk Developer uses the MMC system for automatic control of the hoisting, rotating and pipehandling systems.

MMC is a software tool designed to improve trip-in and trip-out operations, focusing mainly on safety and efficiency. There are other advantages, such as less wear and tear and more constant tripping speeds. By allowing the PLC to carry out pipe handshaking and controlling all the machines simultaneously, one operator can perform tripping faster and safer than what three operators could previously do. A fixed sequence is also more predictable, thus increasing safety on the drill floor. When drill crews are familiarized with the sequence, they will know what each machine will do next. In contrast, with several operators controlling different machines, there is an uncertainty as to how the machines will move next.

Wear and tear on the machines is reduced because MMC operates each piece of equipment in an optimal manner. More constant and predictable speeds are achieved because MMC does not tire out, nor is it very susceptible to the variety of operator experience. As long as the operator is maintaining the speed, acknowledging certain stages in the tripping operation, MMC will handle pipe in the exact same way every time.

Handing over pipe between two machines is where MMC has one of the biggest impacts on time savings. Several newer rig designs have moved setbacks off drill floor, effectively lowering upwards of 1,000 metric tons 20 m down. This increases both stability and variable deck load (VDL), but the consequence is the need for additional machines. Depending on how many additional machines are required and on layout, MMC will help to maintain a good tripping speed.

Design of the MMC is based on a modular principle, allowing it to be applied to a variety of drillfloor designs. The speed, or time-saving factor, is determined by the number of machines, how fast each machine can do its part of the job and how fast interaction between them can be carried out.

This article will look at the development of the system from concept to a fully working automated drill floor. It will look at the control system principle and both hardware and software design. When performance is discussed, it will use a recently delivered sixth-generation semisubmersible, where the setback area has been moved off the drill floor, as an example. The paper will also look at how implementation and testing have been carried out in order to fine-tune the system for maximum performance.

Figure 3: Layout of the pipehandling system on the Maersk Developer.

DESIGN

The main purpose of the MMC is to increase tripping speeds without compromising safety on the drill floor. Increased tripping speeds are achieved in two ways:

• By maintaining a more constant speed throughout a trip-in or trip-out operation;

• By optimizing machine interactions, i.e. pipe handshaking.

The main design philosophy is based on a modular design using existing machine controls to achieve full automation. This will allow the system to be implemented on any drill floor. The first MMC system was implemented on a semisubmersible but can just as easily be implemented on drillships or jackups. Figure 3 shows the layout on the rig in question.

Control system principle

During development of the MMC concept, two main designs were considered. These can roughly be described as either designing new control logic for all the machines working as one, or using existing and proven control logic to operate each machine. The second principle was chosen.

The MMC controller does not contain any machine control logic. Instead, it is designed as a sequence controller, sending requests to the existing machine controllers telling them what to do, much like a human operator would. Feedback to the MMC controller is relayed from the individual machine controllers, omitting the need for new hardware in the field.

With this design, each machine operates as it would if it weren’t in the MMC sequence. This means each machine can be taken out of sequence at any point and run in manual or semi-automatic mode. The added redundancy does require the capability to efficiently control all machines in manual or semi-automatic mode, which will require additional operators during these events. If an unforeseen event causes the sequence to stop or be halted, this capability can be used to rectify the problem. Without stopping the entire sequence, the problem can be solved and the sequence continued. Other attempts at creating fully automated drill floors have not had this feature, thus requiring the sequence to be completely restarted, which can take up to 10 minutes.

To allow for flexibility in the system, certain features like spin in/out is made available from the MMC keypad controls at the appropriate steps in the sequence. These do not require the machine in question to be taken out of the sequence, minimizing the extra time spent if, for instance, a stand has not been completely spun in or out.

Interaction between MMC and the operator is minimized to include only speed control and confirmations at critical stages in the trip in/out operations. All machine speeds are set prior to starting the sequence, with the exception of the V-door machine (VDM). This speed is controlled analogues by the operator because this machine is involved in many stages of the sequence where feedback cannot confirm the state of the overall system. Confirmations by the operator will typically include “pipe in box,” “break out/make up done” and fingerboard latches open/closed. These are places where there is only visual feedback from the system to acknowledge correct status.

Hardware and software

A primary design feature of the MMC is that it normally requires no additional hardware in the field. A PLC connected to same network as the other machine controllers is all that is required. If additional feedback, i.e. new hardware, is required, this is added to the machine controller in question.

For software, the design is based on a modular principle. Each machine in the sequence is represented by a module (blocks of machine code), which in turn is divided into sequence controls for trip in and trip out, command mapping toward the actual machine controller and common controls for all the machines in the MMC setup. In addition, there is an overall control to monitor the sequence. This is used to select the appropriate camera for the CCTV system. It will also maintain the other features of the system, such as initialization, setup, operator messages and machine registration.

HMI interface

MMC has several interface screens to provide the necessary interaction with the operator. The main screen contains statuses for each machine, indicating open/closed status on grippers, etc, correct tilt positions and makeup torque (actual and set point). Operator text asking for confirmation and giving feedback is also shown here. Figure 1 shows this screen.

There are three additional sub-menus: speed setting, where the speed for each machine is set; sequence registration, where machines are taken in or out of sequence; and enable conditions, which is a tool showing which machine is not ready to start the sequence and which statues are missing. The sub-menus are support windows used only when certain situations arise.

CCTV compatibility

With so many machines in motion at the same time, keeping an eye on everything at once can strain the operator. Several different CCTV sequences can be tied into the MMC, which will put the camera where focus is needed on the main screen. This will primarily be where the pipe handover is taking place. Auxiliary CCTV screens will usually have a four-in-one camera image covering everything happening in the setback area.

PERFORMANCE

The experience of the operator will affect MMC’s performance to a certain degree. For this system, it will be evident if the crew does not know the individual machines that are controlled. MMC takes eight complex machines and turns them into one machine performing two well-known sequences – trip in and trip out. If something unforeseen happens, knowledge of the machine will help to solve the issue in a minimal amount of time.

MMC has been implemented on two installations, and both are proving effective. This part will look at the theoretical top speeds that can be obtained with this rig design and what the system is delivering at the time this article was written.

Tripping times – initial design

Each machine in the MMC sequence has an optimal speed for performing its task. The maximum theoretical tripping speed on this rig design is determined by the slower of two “sub-sequences.” The first of these is the one that brings stands from the setback area and delivers them to the vertical pipe chute, which tilts into position where the stand can be picked up by the machines on the drill floor. The second sub-sequence picks the stands from the tubular chute, brings it to the stickup for makeup and handover to the drawworks. Table 1 shows the theoretical time each machine will take to perform its task during a trip-out (TO) sequence, which takes 105 seconds. The following formula is used, given that there are 3,600 seconds in one hour:

This will give us:

Table 2 shows the same time usage for each machine during the trip-in (TI) sequence, which takes 94 seconds, giving us:

Recent updates have raised the tripping speeds in both directions. The system is approaching 38 stands/hr on TO and 41 stands/hr on TI. When this article was written, these new speeds had not been verified through continuous tripping by fully trained operators. It had only been tested by the actual crew, which was in training.

Table 1: Initial-design trip-out times.

Tripping times – training

Tripping times that have been observed during installation and tuning of the system are shown in Table 3. They are divided into groups for the periods when testing were done.

It is important to note that when training like this is executed, the operators are not aiming for maximum speed but rather learning the sequences and how they work.

Duration in the table below refers to the duration of the tripping sequence. A long duration will better show the average speed, indicating the extra time spent if the operator does not pay attention to whether the pipe is spun all the way in or out, etc.

Table 2: Initial-design trip-in times.

INSTALLATION, TUNING AND LESSONS LEARNED

Installation of the MMC system is straightforward because there is no need for new wires from the local equipment room (LER) to the drill floor. The new MMC PLC is installed in LER and connected to the system, followed by upgrades to the operator interface. At this point, the MMC is ready to go. However,  to achieve maximum performance, tuning is required.

Because every rig is slightly different, fine-tuning can save typically between 2 to 15 seconds per stand. In the long run, even two seconds will amount to quite a few stands and is thus considered worthwhile.

Fine-tuning will include finding the optimal waiting positions for each machine without triggering the anti-collision system (ACS). ACS is one of the more time-consuming unwanted events that can occur. If the ACS is triggered, several machines must be taken out of sequence to remedy the situation.

Table 3: Tripping speeds during training (stands and ft/hour).

With new systems like the one described here, there are always lessons to be learned. One that has been clearly observed is the importance of machine knowledge. If the operators do not know how each machine works, solving the problem by taking the machine in question out of sequence will take much more time than necessary.

Another lessons learned is that there is value in discussing such systems with the crew that will work with it, making it as easy to use as possible.

CONCLUSIONS

The following conclusions can be drawn from the discussions above:

• MMC reduces the number of operators needed to perform tripping operations;

• MMC increases safety on the drill floor by giving control to the PLC, omitting fatigue as a risk factor;

• MMC increases efficiency by optimizing interactions between machines;

• MMC reduces wear and tear on the machines by ensuring correct operation;

• MMC allows consistent tripping speeds amongst different operating crews;

• Knowledge of how each machine in the MMC sequence works is still needed to achieve maximum efficiency.

Acknowledgements: The authors would like to thank Kaj Kristensen, Allan McColl and Jesper Holck from Maersk Drilling for their contribution to the paper. We would also like to thank everyone else who has been involved and contributed to this paper and the related presentation.

IADC/SPE 128700, “Fully Automated Pipehandling System on a 6th Generation Drilling Vessel,” was presented at the 2010 IADC/SPE Drilling Conference & Exhibition, New Orleans, La., 2-4 February 2010.

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.

INTRODUCTION

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.

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).

DRILLSHIP OVERVIEW

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.

BACKGROUND

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.

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.

INSPECTION PLAN

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.

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.

SAFETY INSPECTIONS

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.

MOBILIZATIONS AND FIRST WELL IN BRAZIL

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.

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.

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.

GOM OPERATIONS

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).

PERFORMANCE, 2008

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.

CONCLUSION

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.

By Linda Hsieh, managing editor

Gert-Jan Windhorst, Noble Drilling manager health, safety, environment & quality, Europe, is transported from the Noble Homer Ferrington after an inspection in summer 2009.

Having been born and raised in the Netherlands in a family of sailors, it wasn’t particularly hard for Gert-Jan Windhorst to decide that he wanted to major in nautical science at the Hogeschool Rotterdam. Then, after getting his bachelor’s degree in 1977, he started traveling the world offshore, first on refrigerator ships that stored food products, then on barges and dredgers conducting dredging operations around Europe, Latin America and Alaska’s Beaufort Sea.

Those two jobs kept him out on the seas on and off for nearly a decade. It wasn’t until 1986 that he decided to leave the dredging industry, mostly because he had been promoted to captain, which meant that he got to do less of the actual dredging work and much more paperwork. “The captain didn’t get to do the interesting parts of the job anymore,” he recalled.

Mr Windhorst later built his experiences in the agro-chemical and biotechnology industries, developing and managing HSE and quality assurance systems, performing risk assessments and implementing security policies and procedures. By 1996, he had joined Noble Drilling (then Neddrill) as manager of HSE&Q.

Upon joining the drilling industry in 1996, he was impressed by the safety improvements that had been made compared with what he had seen while working as a dredger. “There was a big difference compared with the early ’80s. We had started working more like the process industry with good standards and guidelines. We were doing things to be safer, not just to be faster,” he said.

Yet he knew there was more to be done. Since Mr Windhorst joined Noble, he has helped to develop and implement systems that have reduced the company’s incidents and near-misses by approximately 60% and reduced work-related health and safety risks for platform workers by approximately 40%. Other projects have included developing a patented method of workplace assessment and an integrated “corrective action management” system.

“There’s a lot of behavioral things that still need to be addressed. Why do people do a task the right way 98% of the time but won’t do it the other 2%?” he said. In fact, nearly all safety incidents can be traced back to human behavior. “Is it that they’re tired in those 2% of the time? Is it that they were thinking about something else? We don’t know, but that’s the behavior we need to influence.”

Noble is tackling behavior-related incidents through three pillars – leadership, culture and systems, Mr Windhorst said. Each pillar must be strong before safety can be improved. “It’s the 80/20 rule. You fix 80% of the problems with 20% of the effort, and the last 20% will take 80% of the effort. We’ve been working on that last 20% for some time.”

Mr Windhorst has also contributed significantly to collaborative industry projects on HSE, one of which was the IADC HSE Case Guidelines in the late ’90s. The guidelines are used by drilling contractors to centralize their safety cases across various countries, streamlining what were once duplicative efforts made from one country to another. “It was a good project,” he said. “Having an organization like IADC that will take on projects like these is great. I look at a lot of other globally active industries that don’t have an organization like IADC, and they don’t understand what a blessing it is. You can share your knowledge, and you can speak with one voice.”

Another collaborative industry project that Mr Windhorst is currently developing with a Dutch working group is a standard bridging document. It will aim to align the safety processes of the drilling contractor, the operator and third-party service companies.

“Those processes should be aligned so it’s communicated as one process. That would give employees a better understanding of what they’re doing and prevent mistakes.” He hopes the group can have the document in place in the Netherlands by next year, then eventually get it adopted in other countries.

Despite the vast improvements that the industry has made with HSE over the past decades, Mr Windhorst cautions that we must not take this success for granted: “If you don’t continue to work on health, safety and environment, things will go down again. It’s not a given to stay at this level. We can’t underestimate the risks and work that still must be done. New generations that are starting in our business – they also have to ask questions like ‘Why?’ ‘What if?’ and have the ability to say no.”

Behavior-based safety programs can bring about the next step-change in the industry’s safety performance by motivating all employees to choose the right behavior at all times and in all aspects of their work.

Before we explain what “behavior-based safety” is in today’s oil and gas industry, let’s first ask ourselves: What is behavior management?

There are many textbook answers. The most often heard is associated with behavior-based safety (BBS). A quick search on the Internet for “behavior-based safety programs” leads to an enormous number of links.

Safety professionals believe that behavior-based management applies to all aspects of our work – not just safety but everything associated with performing quality work.

Managing behavior is dependent on understanding why people do things in a specific way. To do that, experts have developed a model to show the human behavior selection process. It is often referred to as the “ABCs of Behavior.” The model aims to show, in a logical and simplified way, how we choose a specific behavior in any given situation.

As we progress through our lives, we continually develop a set of attitudes, values, knowledge and experiences.  This is what gives each of us our unique perception of the world and significantly influences the way we handle any situation in which we may find ourselves. In life, we come across situations that direct the need for us to take action. In this model, those things that trigger the need for us to take action are referred to as “activators.” When we experience an activator, our perception provides a filter and influences our comprehension of that specific situation.

A typical workplace activator could be an instruction given by a supervisor, reading a warning sign or hearing an alarm. Activators direct us to make a behavioral choice. To make that choice, we consider the consequences that we perceive could arise from each of the behavior options available. It is our perception of the consequences that then motivates us to choose a behavior. In general, we make behavior decisions to gain a desirable outcome for ourselves or to avoid an undesirable outcome.

Once we make our behavior choice, the result is the consequences. Sometimes we get what we anticipated; other times we get something quite different.

The model concludes by showing that the consequences provide feedback to give further input to build our perception. Consequences affect behavior in one of two ways: They either reinforce it or discourage the behavior.

Our perception is not only re-enforced by feedback from our own actions but also when we witness other people’s behavior and the consequences. If one person who is a senior employee complains, other employees may start complaining. If the manager starts his meetings with a safety topic, other managers and supervisors tend to do the same. Behaviors that others see positively reinforced are most likely to be modeled.

It is often the case that two people will choose a different behavior when confronted with the same situation. Why?

We are strongly motivated to choose a behavior that provides what we perceive to be a positive outcome. This choice is further strengthened if we also perceive that the positive consequence we anticipate is certain to be delivered – and soon. Therefore, in the language of behavior, “soon,” “certain” and “positive” are often used to describe consequences that are likely to strongly motivate a behavior choice. It is by understanding the simplified human behavior model and our knowledge of “soon,” “certain” and “positive” antecedents that we can begin to appreciate why we do the things we do.

However, in the pursuit of “soon,” “certain” and “positive” consequences, we sometimes make the wrong behavior choice.

AT-RISK BEHAVIOR

Behavior choices can affect any part of our life and work. When parents want to encourage their children to do something or behave in a certain way, they instinctively praise their children every time the child does a certain action or displays a certain behavior the parents are trying to promote. This technique relies on the “soon,” “certain” and “positive” principle.

If the child knows that he will be praised immediately following a desired behavior and that praise always happens after the behavior is displayed, then this represents a positive outcome for the child. This combination of “soon,” “certain” and “positive” activators strongly motivates the behavior choice of the child.

Behavior management is not just focused on safety; it is also relevant to all aspects of the quality of our work. The science of behavior management is to strengthen the perception of the consequences so that they strongly align to motivate choosing the appropriate behavior. By using the simplified ABC model for behavior, we can take our understanding of the concepts and use them to encourage desired behaviors and discourage at-risk behaviors.

The same philosophy is valid whether at home or at work. Our perception of the consequences determines the behavior we choose in response to an activator. The actual consequences provide feedback to further develop our perception.

At-risk behavior can be defined as “any behavior that increases the likelihood of an incident occurring that can lead to negative consequences.” It results when poor perception leads us to misinterpret potential consequences and results in us choosing a behavior that increases the likelihood of an incident. If one is trying to get home from work quickly and chooses to go over the speed limit, he or she may reach home early without having an accident or getting a speeding ticket on the way. This consequence would let him or her misinterpret the future potential consequences of choosing the at-risk behavior of speeding.

SAFETY EVOLUTION

It is now a good time for the industry to be focused on behavior management. Look at the evolution of prevention and mitigation programs in the oil and gas industry and you will see certain stages of well-marked improvement. The industry has a lot of broad-based, well-educated people, and the safety culture in the industry has improved significantly. This improvement has come in stages, and, as each process stage matured in the evolution of safety, the rate of performance improved but flattened after showing improvement.

In the first stage of the formal HSE evolution, traditional safety programs such as PPE, safety signs and machine guarding, etc, were introduced. These programs typically addressed the low-hanging fruit of safety improvement.

In the next stage of development, more powerful tools were added. These were often extensions of the initial programs but more sophisticated. In the next stage, the effect of the implementation of QHSE management systems, including global standards and the power of information technology systems, was realized, and a significant improvement was seen.

What can bring about the next step-change in the industry’s safety performance? Because the systems are already in place, we need people to implement them. We need a system that motivates all employees to choose the right behavior at all times and in all aspects of their work. This can be managed through behavior-based safety programs. The goal of these programs is to encourage safe behaviors and correct at-risk behaviors in the workplace.

At Schlumberger, this program is called “WorkSMARRT,” a term used to convey behavior management of all types of risks – certainly safety but also environmental management, service delivery, work-product quality and so forth.

Using knowledge of human motivation and behavior to manage safety is not new to the industry or Schlumberger. However, WorkSMARRT represents the first time the company has used a single overarching name to organize its behavior management efforts in all segments and functional applications.

The initiative is supported by three main components: accountability, risk management and communication.

Accountability is a shared commitment and an obligation of every employee to intervene not only when they see something wrong but also when they observe something right, to encourage the continued use of correct behaviors.

Risk management is about differentiating the right ways from the wrong ones. Active participation in hazard identification and the analysis of associated risks is a key behavior that every employee must strive to develop. It is imperative that one understands all the activities involved in a process so that any exposure to hazards during those activities is recognized, and one can apply appropriate risk-control measures to eliminate the risk or reduce the risk to an acceptable level.

The company has a hazard analysis and risk control (HARC) standard for all operations. It describes what to do and what tools to use when doing hazard analysis and related risk control. At-risk behaviors can be anticipated and documented using this process, and the appropriate prevention and mitigation measures planned.

Communication is a vital part of WorkSMARRT. People communicate with each other to determine what is required and to understand what needs to be done. The “RR” in WorkSMARRT represents “recognize and respond.” This principle applies to the improvement of one’s own behaviors by requiring every employee to recognize consequences accurately and respond with appropriate behavior choices.

Additionally, one can recognize when others are choosing an at-risk behavior and must be prepared to respond by intervening. Employees are required to take time to observe fellow workers and their workplace and intervene appropriately. As one recognizes the need to address behavior factors, the need to know how to respond also becomes very important.

Schlumberger introduced the Observation Intervention Program under WorkSMARRT. The program gives everyone absolute authority and an obligation to stop any activity that may threaten service or product quality, health, safety or the environment.

The program gives managers the resources they need to support their teams in complying with quality and safety standards. The Integrated Project Management (IPM) group of Schlumberger initiated the program through its worldwide operations in 2010. It soon became clear that the intervention techniques, though seemingly simple, are complex, and that workers require specific training and practice in order to implement them.

Two training programs were developed for the Observation Intervention Program. Level 1 training was developed as an awareness-level initiative applicable to each employee of IPM. This level of training was based more on what is the observation intervention program and why it is being implemented.

A second, more advanced level of training was developed, Level 2 training. The target audiences for this training were line managers and field supervisors. Level 2 training is a combined classroom and field-practice training program, and classroom studies were based on these modules:

1. Introduction

2. STEPS of an observation intervention

3. Human factors

4. Classroom workshop

5. Reporting in Quest (company database)

6. Supervisor toolbox

The program focuses on the behavior aspects of the safety programs already in place. Employees can report on different issues related to driving, injury prevention, the environment or general observational interventions based on the correct or incorrect use of specific techniques.

For example: Observers may report the safe or at-risk behaviors regarding driving techniques taught as part of the company DriveSMARRT program. The same is true for the Schlumberger Injury Prevention Program (SIPP), and an SIPP observation intervention could report on the correct or incorrect use of the injury-prevention techniques witnessed. The data that will be available after a few years into the program will help the company direct the human and financial resources where they are most required.

Genuine management commitment is critical to the success of such behavior-based safety programs. Top-level managers have recognized the value of the program as it was rolled out globally with a message of support from Schlumberger IPM president Miguel Galuccio.

The program is seen as a tool that can make the difference between life and death and may stop a catastrophe even when all other systems have failed. It is being practiced by thousands of employees across the globe, and it is our belief that such an approach will bring about the next step-change in the safety culture of this company.

WorkSMARRT is a mark of Schlumberger.

References:

Ayers, H. (1995), “Perspectives on Behavior: A Practical Guide to Effective Interventions,” David Fulton, London.

Bandura, A. (1969), “Principles of Behavior Modification,” Holt, Rinehart & Winston, New York, NY.

Daniels, A.C. (1989), “Performance Management: Improving Quality Productivity Through Positive Reinforcements,” PM Publications, Turker, Ga.

DePasquale, J.P., Geller, E., 1999, “Critical Success Factors for Behavior-Based Safety: A Study of Twenty Industry-Wide Applications.” Journal of Safety Research 30, 237–249.

Geller Scott, 1994, “Ten Principles for Achieving a Total Safety Culture.” Professional Safety, pg 18.