By Michael (Rick) Johnson and Kevin Ardoin, Halliburton; Bill Bullard, Eni

Figure 1: The components of the original expandable liner hanger system include an integral liner hanger/packer assembly combining an upper tie-back receptacle with elastomeric elements bonded directly to the hanger body.

When drilling offshore wells, wellbore casing strings larger than 13 ^5/8-in. typically are required to be “hung off” in the casing hanger at the wellhead. To date, this has been the most widely used method, although it is a time-consuming and usually a very costly approach. To alleviate time and cost issues, a new expandable technology has been developed as an alternative to the conventional approach.

The new solution is an expandable large-bore liner hanger that allows an operator to set a liner instead of a full string of casing. Successful applications of the new large-bore expandable liner hanger were first run in other parts of the globe, and plans for operations within the Gulf of Mexico region were then initiated.

This article presents an overview of the development and successful installation of the first large-bore expandable liner hanger (LBELH) in a deepwater Gulf of Mexico Eni Triton well. Advantages of this technology included casing placement flexibility; redundant seals at the top of casing; improved load support reliability; the capability of rotation and reciprocation during cementing; cost reduction; elimination of requiring the casing hanger to seal in the casing adapter; and no complications with shallow deviation. A summary of the actual gains included:

• Greatly lowered equivalent circulating densities resulting from the slick-bore design of the system;

• Greatly improved cementing quality from the capability to rotate and reciprocate during cementing; and

• Having run-in speeds with no mud loss.

These features are expected to increase well life and reduce future remedial work to the well. In addition, by eliminating the requirement to precisely space out liner jobs on floating rigs in deepwater regions, the pressure integrity issues often experienced with conventional systems can be alleviated.

With expandable technology proven as a result of its capability to reduce problems experienced with traditional liner hangers in difficult wellbore scenarios, the time had come to pursue large-bore expandable liner hangers.The main com ponents of the expandable liner system are an integral liner hanger/packer assembly combining an upper tie-back receptacle with elastomeric elements that are bonded directly to the body of the hanger.

Figure 1 shows the basic components of the original expandable liner hanger system. The bonded elastomeric elements compress against the parent casing as the hanger expands; this action virtually eliminates any leak paths between the liner, liner hanger, and previously run casing, maintaining the pressure integrity of the wellbore.

A compromise lies within the design of conventional large-bore liner hanger technology in which increased tensile capacity will decrease the flow area, creating higher pressures during cementing operations. Large-bore expandable liner hanger technology answers this compromise with a slick-bore outer diameter and an extensive collet design to handle tensile capacities without giving up the flow area needed to achieve a successful cement job.

Restrictions for conventional equipment lie within the landing profile needed to create the seal between the casing hanger and parent casing, creating tight tolerances and a place for debris collection and pack-offs. With expandable technology, the restriction is eliminated until expansion after the cement job.

In order to reach total depth with large casing sizes, operators usually begin their well plan using large-diameter casing that would be anchored at the seabed.When drilling offshore wells, typical wellbore architecture will require that casing strings larger than 13 ^5/8-in. be “hung off” in the casing hanger at the wellhead.

Table 1 shows specifications for the Eni Triton hanger. The hanger was designed to fit through a restriction introduced by a high-pressure wellhead housing while maintaining flow area and pressure integrity.

Wellbore architecture for deepwater drilling generally uses 36-in. x 20-in. x 16-in. x 13 ^5/8-in. x 11 ^7/8-in. x 9 ⁷/8-in. x 7 ^3/4-in., or 36-in. x 28-in. x 22-in. x 18-in. x 16-in. x 13 ^5/8-in. x 11 ^7/8–in. x 9 ^7/8-in. x 7 ^3/4-in. strings, or some variation. Aside from the 36-in. casing, all of the top casing strings through the 13 ^5/8-in. are typically landed and “hung off” at planned depths in casing profiles located at the wellhead or prior casing strings (parent casing). The 20-in. and 13 ^5/8-in. casing generally will be landed out in the wellhead versus the 26-in. or 28-in. casing, and the 16-in. or 18-in. casing sizes will usually be landed in profiles located in previous casing strings.

Not landing in wellhead profiles is where the problem occurs. Landing in previous casing string profiles tends to restrict flow and build up debris and pack off around the profile. This causes problems with the cement job and can interfere with a proper seal. The 16-in. x 20-in. and 18-in. x 22-in. expandable liner hanger systems were developed to eliminate these issues.

In the first job in the Gulf of Mexico (GOM) to set an expandable liner hanger in the previous casing without a landing profile, the large-bore expandable liner hanger provided the flexibility of placement of the liner, which offered reliable support and proven redundant sealing technology. The capability of rotating and reciprocating during cementing operations enabled an enhanced cementing performance.

Additionally, the large-bore expandable liner hanger improved operational economics by requiring less casing in the well, simplifying proper seating in deviated wellbores and eliminating the need for a proper space-out before running the liner to reach the planned destination.

The development began with an idea to provide solutions for a major customer in Baku in 2007. They wanted the large-bore expandable liner hanger to provide a quality seal at the wellhead with the flexibility of placing the liner. After the successful installation of five runs in other areas, Eni decided that this method could provide a suitable solution for a difficult wellbore scenario in the Triton Field in the GOM.

Job Planning

The newest obstacle for the liner system was the restriction introduced by the high-pressure wellhead housing that had a 17.574-in. drift restriction. Prior to introduction of the large-bore liner hanger, the largest diameters that would pass through this restriction were the bit/hole opener (17.50-in. nominal) and the 16-in. conventional hanger. The large-bore hanger was designed to fit through the restriction while maintaining flow area and pressure integrity. The specifications are shown in Table 1.

Deviation drives need for new planning solutions

With +/-20° deviation at the 20-in. shoe and a +/-54° deviation at the 16-in. shoe, the large-bore expandable liner hanger became the prime candidate for the upcoming job. After receiving exceptional performance from expandable liner hangers in the past, Eni was optimistic about improving their chances of a successful job by using the 16-in. x 20-in. large-bore expandable liner hanger.

Due to the likelihood of cement presence above the top of the liner, the lead pump time was extended by 24 hrs, and cement volumes were increased. More volume typically reduces contamination; thus, good cement properties (right-hand set, good ultimate compression, and low fluid loss with “tight and flexible” properties that prevent annular flow) are maintained. For the purpose of simplification for the first run in the GOM, surge-reduc tion equipment would be left out of the plans, but future use of this equipment was anticipated.

Benefits: Running Large-Bore Expandable Liner Hangers

Figure 2 shows components of the large-bore expandable liner hanger running tool.

The significant advantage for large-bore expandable liner hangers lies within deepwater operations with elevated costs in rig time and delays due to complications during mudline/casing hanger installation. Deviation will cause unreliable seals where casing is to be “hung off” and differential pressure will cause the liner to prematurely “stick,” not allowing the casing hanger to reach its ultimate destination.

Large-bore expandable liner hangers help to reduce risks by 1) having redundant, reliable and proven seals that expand against the previous casing internal diameter, 2) by being capable of working casing to depth with high-torque capabilities, and 3) by not requiring advanced space-out designs. Figure 3 compares the complex conventional casing hanger system with the simple large-bore expandable liner hanger.

Benefits of the LBELH include eliminating the need to land the 16-in. liner at a fixed point in the wellbore. With deviation playing a key role of “spoiler” when trying to get the conventional casing hanger to the desired depth, the LBELH can be set at whatever depth gives the best integrity to the string. The capability to rotate and reciprocate during the cementing job would prove beneficial with high deviation at the liner shoe.

Additionally, the large-bore expandable liner hanger will hold its rated anchor loading in both directions; whereas traditional designs do not have the capability to hold forces applied from below, thereby allowing the liner/casing to rise. This feature could become even more significant as development moves into deeper environments.

Eni ran the first large-bore expandable liner hanger assembly in the GOM on 13 May 2010 with the installation of a 16-in. x 20-in. system. At the time of deployment, this was the second system run in the world (the first being in Baku). The job was a success and was considered an “enabling” technology for this well.

The well was highly deviated at 55° in the 16-in. section with a shallow kick-off, which was not the typical well configuration in the Gulf. The usual recipe with a conventional 16-in. casing hanger would not suffice for this atypical well. In previous wells, the cement job would be performed, and then a pack-off seal would be made.

With no rotation possible, the only allowable option was washing down. The well parameters for an earlier job performed in the MC 782 #2 (Triton) well were:

• Water depth of 5,376 ft;

• Rotary kelly bushing (RKB) mud line at 5,465 ft;

• 36-in. at 5,792 ft;

• 26-in. at 6,465 ft;

• 20-in. at 8,020 ft MD/7,981 ft TVD with a 23° inclination;

• 16-in. at 9,636 ft MD/9,252 ft TVD with 54° deviation; and

• Liner top at 7,703 ft MD/7,684 ft TVD with an 18° deviation.

The chances of landing on the 16-in. casing hanger were good when there was no deviation, and the chances for successful landing dropped with increasing deviation. Because of the difficulty associated with deviation of getting a good seat, pulling the 16-in. would likely have caused swabbing and well control issues.

Figure 3: Comparing the complex conventional casing hang-off system and the simple large-bore expandable liner hanger, the expandable liner hanger reduces risks through redundant seals and high-torque capabilities.

Because of the design of the profile in the 20-in. casing and debris buildup in restricted areas with possible pack-offs, losses while running and cementing were frequent. Acquiring a seal would be a challenge because restricted areas can be full of debris and will flow back due to losses to the formation. This event complicates setting the seal due to piston force.

The benefits gained by using the large-bore expandable liner hanger would include high torque and tensile capabilities, no need for a predetermined depth or space-out, improved cement jobs because of no restrictions and less chance of losses, inner string cementing replaced by conventional cementing with drill pipe darts and casing wiper plugs, and time savings.

With wellbore deviation one of the key factors in the development of the LBELH, the new technology is now considered an enabler for the completion of deviated wells and shallow kickoffs. With the use of a conventional system in this scenario, the well path and/or surface location would have had to be changed, costing an additional $20 million to $30 million.

One of the most exciting advantages was the fact that the deviated well path that could be used led to the discoveries of new shallow reserves, which were otherwise hidden by salt in vertical drills. While best practices are not always to test new product lines on key wells, the warranted the use of the new LBELH technology. Although the Triton well was atypical for the Gulf, the development team met all challenges, and the installation of the first LBELH for the GOM was completed successfully in May 2010.

In deepwater operations, fighting a loss of returns, setting the hanger at a predetermined depth and establishing a seal between the 16-in. and 20-in. casing are always concerns. Assuming the 16-in. hanger would reach the predetermined depth, the restricted clearances involved in a profile hanger still cause concerns of accumulating debris and packing off. Without movement because of fear of being stuck off seat, a pack-off would continue to get worse as more cuttings would try to pass the pack-off.

Since the large-bore expandable liner hanger does not land on seat and does not reduce wellbore clearance prior to cementing, debris and cuttings are allowed to pass without restriction. Reciprocation and rotation during the LBELH job are possible, which comes into play when reciprocating to break pack-offs and maintain returns, creating a significant operational gain. The adaptation of surge reduction is straightforward. The logic for an improved cement job is still viable, especially since the primary objective is generally to obtain a good shoe leak-off.

Another consideration is that it is not necessary to run and pull the inner string during cementing, which saves rig time.

For running future vertical wells with expandable liner hangers compared with previous methods, the risked cost savings has been estimated to be approximately US$2.2 million per well, excluding casing savings, from:

1. 100% of inner string savings: 10/24 x $1.3 million (100%) = $540,000 .

2. 30% from additional runs to clean out and reinstall pack-off: 48/24X $1.3 million (30%) = $780,000

3. 20% squeeze of shoe: 72 / 24 x $1.3 million (20%) = $780,000

4. 60% loss of the 750 bbl of synthetic-based mud (SBM): $225 x 750 (60%) = $101,250

5. Due to losses on a cement job, Eni could also have incurred a plug and abandonment liability, which would then have required perforating and squeezing cement into the 16-in. x 20-in. annulus.

6. Estimated additional rig cost for two days would be $2.6 million. If plugging could not be initiated immediately, bringing the rig back for re-entry would add an additional $7.8 million (six days) to the OPEX.

The successful installation of the first large-bore expandable hanger in the GOM was completed in May 2010. An improved cement job resulted from the reduced equivalent circulating density combined with the rotation and reciprocation capacities of the hanger. By enabling a more efficient cement job, it is expected that the life of the well will be improved, and the need for future remediation work will be reduced.

An additional benefit from the use of expandable liner hangers on deepwater floating rigs is that there is no requirement of space out of the liner. This eliminates pressure-integrity issues that can occur with conventional systems when space out is improper.

The 16-in. x 20-in. large-bore liner success has solidified ENI’s future plans for continued use of the large-bore liner hanger.

Cantu, J., Smith, P., Nida, R., “Expandable Liner Hanger Application in Arduous Well Conditions Improves Reliability: A Case History,” paper SPE 88510 presented at the 2004 SPE Asia Pacific Oil and Gas Conference and Exhibition held in Perth, Australia, 18–20 Oct.

Jimenez, C., Soto, S., Leon, A., Batocchio, M., Marval, P.,  Schoener-Scott, M., “Case Histories: Implementation of New Liner Hanger Technology in South Central Venezuela Significantly Improves Operations in Complex Wells,” SPE 118387 presentation at the 2008 Abu Dhabi International Petroleum Exhibition and Conference held in Abu Dhabi, UAE, 3–6 Nov.

Moore, M.J., et al., “Expandable Liner Hangers: Case Histories,” paper OTC 14313 presented at the 2002 Offshore Technology Conference, Houston, Texas, USA, 6-9 May.

Nida, R. et al., “Innovative Expandable Liner Hanger Application Saves Time on Pinedale Anticline Drilling Operations: Two Case Studies,” paper SPE 90192 presented at the 2004 SPE Annual Technical Conference and Exhibition held in Houston, 26-29 Sept.

By Katie Mazerov, contributing editor

The drilling optimization pyramid is the cornerstone of a drilling strategy that National Oilwell Varco uses to help operators improve drilling performance through its Wellsite Performance Drilling Advisor program. Data is the most important element because information, knowledge and everything else are derived from data. Source: Russell Ackoff

Like motherhood and apple pie, drilling optimization is one of those things that everybody loves and no one can get enough of.  Across the board, operators, drilling contractors and service companies are constantly striving to improve drilling performance and reap the benefits it can bring in terms of efficiency, cost savings and safety.

But while the push toward this ever-challenging objective may be universal, paths for getting there aren’t always the same. And in an industry where new methods are continually emerging, at least some operators believe that drilling optimization is a holistic process – that it’s not just about tools and technology. Data analysis is also a crucial piece of the puzzle.

“Drilling optimization should be a process to improve drilling performance with a balance of new technologies, training and data analysis,” said Dr David Chen, senior drilling engineering advisor of Exploration and Production Technology for Hess Corp, which recently launched SmartDrill, a drilling optimization program, in North Dakota. “It means being more efficient, not only with drilling but also completions. When we drill more efficiently, we also create a better wellbore, and that better wellbore will improve casing and completions runs. Also, if everyone is focused on drilling optimization, improved safety will follow because people are more aware of what is going on.”

Technology advances, such as pressure-while-drilling (PWD) to measure downhole pressure, are an essential part of drilling optimization, Dr Chen believes. “Before PWD tools came into the market 15 years ago, we had no way of knowing the downhole pressure. That technology opened up a lot of applications,” he said.

Another key development was the vibration sensor. “One of the major causes of nonproductive time (NPT) is bit, downhole tool and measurement while drilling (MWD) tool failures,” he said. “And a primary cause of those failures is downhole vibrations, which often cannot be detected on the surface.”

But technology has its limitations. For example, bits and downhole reamers often do not sync well. “This can cause problems, particularly in the Gulf of Mexico, where a downhole reamer is needed for most of the drilling,” Dr Chen said. “There is a technology gap to keep the bits and the downhole reamers drilling at the same rate to last through the section.”

Another limitation involves polycrystalline diamond compact (PDC) bit technology, which, although greatly improved over the past 10 years, cannot be used in some hard formations, such as those encountered off the west coast of Africa. The cost and reliability of rotary steerable systems (RSS), still mostly used in offshore drilling, also pose barriers. “If the cost of RSS decreases and reliability improves, we would use it in more operations,” he explained.

The rate at which new tools and technology enhancements are coming into the market presents a dilemma in determining which new technology is right for each well that is drilled, from the bit to the bottomhole assembly (BHA) to the drilling parameters, Dr Chen suggests.

“It’s hard to know which new tools are really going to work. For example, a new downhole tool that can reduce vibration may not be applicable in certain formations. The application is not universal,” he said. “The same is true with optimization software.” Another issue is that unless a tool is already being used and has a track record of proven results, operators are reluctant to embrace it. “This is why data analysis is so important. Whenever we use a new tool, we need a benchmark to test against. Otherwise, we don’t know if it is working.

“My view is that new tools are essential, but data analysis is equally important,” Dr Chen continued. “Without data analysis, we don’t know if the systems are working or, more importantly, if they are not working.” Training is also critical in this regard. “We need to ensure that we train people so they understand the tools and can easily analyze the data properly,” he said.

Hess Corp recently launched a drilling optimization program in North Dakota called SmartDrill. Whereas a lateral section used to require three BHAs and the bit was severely damaged (left), after SmartDrill was implemented, only one BHA was needed to reach TD and the bit that was pulled looked like new (right).

Drilling optimization programs have made a difference for companies in minimizing cost, improving safety and achieving greater efficiency, Dr Chen noted. Earlier this year, the SmartDrill optimization program, which uses the mechanical specific energy process, was deployed in a pilot program in the Bakken Shale play in North Dakota. The target for the next five years is to lower drilling costs by 10% and increase the drill rate per day by 40%.

“Just reducing the costs will result in a savings of hundreds of millions of dollars per year,” he said. “We’ve seen great results so far with better production and faster, more efficient operation. We believe there is the potential to implement this technology in all regions of Hess, offshore and onshore, over the next few years.”

While technology has its place when it comes to performance drilling, it plays second fiddle to data analysis, according to Graham Mensa-Wilmot, drilling engineer advisor for Chevron’s MAXDRILL team. “Performance drilling is the process where decisions made toward improvements in drilling are driven by detailed analysis of relevant data, regardless of the technology being used,” he said. He maintains that the industry is not seeing the level of improvement in performance drilling that it should – a point of view he says has been expressed by other experts – due to the fact that the tables are usually reversed, where technology is placed ahead of data. “There continues to be pockets of excellence, but the gains are usually not sustainable,” he said. “People with active roles in data mining and analysis have sweeping perspectives on the current contributions of performance drilling. Generally, it is agreed that performance drilling is not having the expected impact on the industry’s performance improvement initiatives.”

While acknowledging that drilling has become more complex and considerably more challenging in recent years, Mr Mensa-Wilmot contends that is not the problem. “Yes, we are drilling deeper, into hotter and harsher environments, but the rocks have not changed,” he said.

“There is evidence that in most cases, drill-ability characteristics of rocks encountered at shallower depths on older projects are comparable to those encountered at deeper depths on new projects. Consequently, the noted differences in performance drilling cannot be solely attributed to the rock. Most people in the industry believe the only way to confront a challenge is with a new tool or technology. As is obvious, we have more technology today than we did 10 years ago. However, achieved performances have not matched the technology growth. The real emphasis should be on data analysis. This is what performance drilling is all about.”

New technologies are always being developed, Mr Mensa-Wilmot continued, and that is a good thing, particularly new techniques for logging tools, as well as tools that can withstand high temperatures and pressures. “Based on data analysis, we will know and understand what has happened, how it happened and why it happened,” he said. “With this background, solution strategies can be developed.”

Consequently, he also notes that it is more critical to have the right technology and not just a new technology. “Rather than simply embracing the latest technology, the industry should be digging deeper into and solving the real problems, not just treating symptoms.”

The culprits in what he calls a “disconnect” are lack of training and an ingrained culture. Often, he says,  people rely on their experience, or rules of thumb, to address problems, while neglecting the data. “Our experience should guide and help us understand the data faster,” he explained. “Experience brings you closer to reality and tells you how you did something in the past, but data can help you improve continuously. Experience will help you understand the data, but analyzing data with an open mind is always better.”

Hess’ target for the SmartDrill optimization program in the Bakken for the next five years is to lower drilling costs by 10% and increase the drill rate per day by 40% on rigs like this Nabors Drilling unit.

National Oilwell Varco’s Instrumentation, Monitoring and Optimization (NOV IMO) product group relies on data to provide real-time service to help operators improve drilling performance through its Wellsite Performance Drilling Advisor program in several regions in North America, including the Fayetteville Shale play.

“Data is the building block of everything we do,” said Steve Vogel, product line manager, Drilling Solutions. “We help operators optimize energy at the bit by reducing bit-related and downhole vibration-related dysfunctions.”

The company’s 24/7 real-time technology center in Houston streams in one-second data from the rig.

The process does not involve deployment of downhole tools. “The use of our service does not require that we have downhole data or downhole tools.  We can operate using surface data,” Mr Vogel explained. “But if the tools are there, and if downhole data is available, we have access to it. But we typically provide our service simply by using the equipment that the rig has available or based on the rig survey we initially perform.”

In addition to data management and monitoring, the system covers everything from the initial engineering analysis to rig personnel training and support, knowledge management using industry best practices across the rig fleet and field, and continuous improvement methods to address and prevent dysfunction.

The cornerstone of the drilling strategy is a drilling optimization pyramid, with data being the most important element, followed by information, knowledge, understanding and wisdom. Mr Vogel noted, “Without accurate information, we can’t gain the valuable knowledge which leads to wisdom. Our customers don’t want data,” he said. “They want information. We derive the knowledge from the data so we can help them drill wells more effectively.”

NOV IMO’s work for an operator in the Fayetteville shale play began in January 2009 as a pilot project with six rigs and has since expanded to 15 rigs in three fields. The company is now providing service for other operators as well. As in other shale plays, a hard boundary, in this case called the Hale sand, sits above the Fayetteville.

“Getting through the shale is a slow and tedious process,” Mr Vogel said.  “The more optimally we can drill through the shale, either by presenting a better-quality wellbore at the end of that drilling, or less time, or fewer bits, the more we are ahead of the curve.” Lateral drilling begins at the upper boundary and then moves into the lower Fayetteville.  The region is also characterized by complex geography, including several fault lines.

But the bigger challenge is that multiple rigs are operating at once with a limited number of engineers to support those rigs, Mr Vogel pointed out.  “Unlike some operators who may have several engineers for one rig, this operator has one engineer for several rigs. That is the nature of drilling in these shale plays,” he said.  “By partnering with us, the operator can get the help he needs for drilling optimization without having to expend a lot of capital or bring on more people. So, the cost/benefit of using our service is very attractive.”

The system engages from a computing platform on the rig to operate the communications and data acquisition system. “Through a satellite system, we transfer data back to our service center, where our technicians monitor the data and ensure the sensors that are providing the data are operating properly,” Mr Vogel said.

Training is an essential part of the program. “The person who has the most availability to make the most immediate and effective impact is the person on the rig,” he noted. “So, we try to transfer as much knowledge as we can down to the rig level by educating the personnel on drilling dynamics, drilling mechanics and drill optimization theory.”

The economics of the program, based on studies conducted over a year, show an average savings per well of more than $135,000, a 39% decrease in drilling hours and a 29% decrease in average days on the well. “The wisdom we gain from data is what allows us, in partnership with our customers, to do the right thing,” Mr Vogel said. “We’re helping the operators build a whole drilling strategy that gives them the return on investment they want.”

By Julmar Shaun S. Toralde, Weatherford International

Weatherford’s SeaShield Model 7875 Below-Tension-Ring RCD has been designed and field-tested to support riser tension requirements as high as 3 million lbs.

Managed pressure drilling (MPD) recently took a big step into deepwater environments with the installation and utilization of the industry’s first rotating control device (RCD) made up below the tension ring and integral to the riser package of a dynamically positioned (DP) drillship. As of June 2011, the Weatherford Model 7875 Below-Tension-Ring (BTR) SeaShield RCD has been successfully deployed on three rank wildcat deepwater wells in Indonesia at water depths of more than 6,000 ft.

The RCD is a key component of the deepwater MPD system that contains annular flow and redirects it to help form a closed-loop circulating system. Designed for use on a DP drillship, the system optimizes the drilling process with a closed-loop circulating system. It provides early kick and loss detection and enhances the riser gas-handling system by allowing early detection of riser gas breakout and facilitating pressure control for the same. The system also enables pressurized mud cap drilling (PMCD) in the event that severe circulation losses are encountered when drilling through carbonate formations.

In the configuration used for the pro ect, the RCD forms part of what is called an MPD riser joint – together with a surface annular BOP and a flow spool – that is installed through the rotary table when the riser and BOP are deployed. Another major component of the deepwater MPD system is the Microflux control MPD choke manifold, a specialized 5,000-psi manifold equipped with dual chokes and instrumented with a Coriolis mass flowmeter and precision pressure sensors.

For this application, the Model 7875 BTR RCD is installed above the intermediate riser joint and below a standard slip joint about 140 ft below the rig floor and roughly 40 ft below sea level. Hydraulic and electrical connections below the water line are made via a subsea-rated hydraulic stab plate. The plate, which is connected to a dedicated 300-ft long umbilical cable, features multiport connections that speed line deployment and makeup while eliminating multiple control cables.

The BTR RCD is the first RCD designed and field-tested to support riser tension requirements of as much as 3 million lbs. Prior MPD operations aboard floating vessels have been configured with a surface RCD above the water line and the tension ring. Because the new RCD is made up below the tension ring, no modifications are required to the riser’s telescoping slip joint or the rig’s mud returns system.

The device allows conventional use of the riser with full-bore access to the well and provides the flexibility to easily transition between conventional and MPD drilling methods. The RCD bearing assembly, with an OD of approximately 19 in. (492 mm), is deployed through the rotary table and tension ring components. With the bearing assembly removed, the RCD is capable of handling full-size 18 ^3/4-in. BOP tools.

The inside profile of the RCD body contains a hydraulic latch that is designed to receive, retain and release the bearing assembly with locking dogs. These locking dogs use a C-latch type system, which is more resistant to debris and solid intrusion. It has a 21 ^1/4-in. x 10,000 psi API flange on the top and at the bottom.

The BTR RCD has a logging adapter that can be installed in lieu of the bearing assembly on the RCD body, thereby providing a means of logging under pressure through the RCD in a safe and controlled manner.

The BTR RCD also comes with a contingency RCD system that uses a specialized housing that allows for the RCD system to be landed in the annular BOP. Using the contingency RCD system allows MPD operations to continue even if the seals on the RCD body have been compromised.

It is basically an RCD bearing assembly made up to a long tubular extension below it. The specialized housing is run in until it sits on a profile on the RCD body and until the housing’s extension has already passed through the surface annular BOP below it. The surface annular BOP is then closed on the extension, thereby providing the seal required for closed-loop drilling while the bearing assembly above it facilitates rotation of the drill pipe without relaying rotation to the surface annular BOP.

The Model 7875 Below-Tension-Ring RCD was a key component of the MPD system that was used to drill targeted depths in the challenging fractured carbonates offshore Indonesia.

The RCD used in this project is the first of many in the Weatherford fleet that complies with and is certified to the drill-through specifications of API 16 RCD. Using this industry standard, the RCD has been rated to static and dynamic pressure ratings of 2,000 psi and 1,000 psi (at 100 rpm), respectively.

In order to put in proper perspective, the significance of the development and deployment of the submerged RCD system, a historical overview of the evolution of the offshore RCD applications is provided below.

The RCD has gone through a long and arduous evolution process to reach the point where it can offer deepwater MPD capabilities to all the types of floating rigs, including those that are dynamically positioned.

Weatherford performed the first documented RCD application on a floating structure in 2004 using a high-pressure Model 7100 RCD. The application aboard a submersible rig was aimed at drilling Malaysian carbonate formations where high fluid loss was a problem. This use advanced the adoption of the technology to a floating rig platform. The concept was called RiserCap, as the RCD was installed on top of the riser during MPD operations. The technique was successfully used and replicated in other floating drilling units in other areas, even in drillships of the moored type.

The RiserCap system, however, has significant limitations due to the RCD being designed for surface applications on land and fixed rigs offshore. Because the pass-through size of the RCD does not allow passage of the BOP test plug, the RCD and its ancillary components must be rigged down when testing the BOP. It also limits the use of the RCD, and consequently MPD, to the lower and smaller hole sections of the well, which runs against the mindset of deepwater drilling operations, where larger hole sizes and contingency casing strings are the norm.

The riser slip joint also needs to be in the fixed and collapsed position in the RiserCap application to allow for a higher pressure rating for the system. This compromises the heave compensation system of the floating drilling installation involved.

Difficulties were also encountered with RiserCap methods in relation to transitioning from conventional to MPD operations with the RCD in place. The RCD involved in a RiserCap system does not have an upper flange, and when installed it removes that ability to route returns through the rig diverter. Instead it sends returns through the return line attached to the outlet of the RCD. This renders useless certain components of the conventional well-monitoring system and makes it more difficult for the rig crew to adapt to the new system.

An intermediate solution to the issues identified with the RiserCap system was introduced in 2008 with the deployment of Weatherford’s first SeaShield series RCD. Devices in this series are purpose-built for harsh offshore environments and have features that enable full integration into the riser.

Compared with a typical surface application where the RCD sits atop the BOP and requires only a bottom flange to bolt it to the stack, integration with a riser system above a subsea BOP required a new RCD design that could be connected at the bottom and the top. In the docking station (DS) versions of the SeaShield RCD, the device is equipped with a top flange that makes installation and integration with the marine riser system possible. This allows the RCD to remain connected to the rig diverter housing at all times. In this set-up, the slip joint is placed higher in the riser string, with the RCD and an annular preventer with a flow spool now situated below the slip joint.

Using the Model 7875 DS system, the RCD bearing and packer assembly is installed through the diverter housing and marine riser system when operations need to shift to MPD mode. This rig-up allows the well to be drilled conventionally with all of the MPD equipment already in place. Once MPD operations commence, the bearing assembly is installed, the valves are opened and drilling can resume in MPD mode without any further rig-up requirements. In circulating mode, returns are taken up the flexible flow line. If PMCD operations are required, cap fluid can be injected through the flexible flow lines.

More importantly, the design of the earlier Model 7100 RCD required the presence of service personnel in the moonpool area at times when the RCD is in use, thereby exposing personnel to a higher degree of risk. The challenging physical location of the RCD far below the rig floor makes it difficult to deploy personnel and presents a higher-risk work environment. It also makes new demands on installing, maintaining and operating an RCD.

The Model 7875 docking station eliminates the need for personnel in the moonpool area, enhancing the safety of offshore MPD operations.

In a significant design advance, the Model 7875 DS enhances the safety of offshore MPD operations by using a remotely operated hydraulic latching system that allows bearing and sealing elements to be changed without the need for personnel in the moonpool area. A special running tool for the bearing assembly and ancillary equipment facilitates rig-floor positioning and removal.

However, both the RiserCap and Docking Station applications are only feasible and practical on moored floating rigs, as the RCD normally has hoses, piping and valves connected to it that need to pass through lines attached to the tension ring. This set-up does not translate well when considered on a dynamically positioned vessel, as the MPD ancillary equipment will end up snagging the lines when the vessel rotates.

Installing the RCD below the tension ring surmounts this difficulty and facilitates rig rotation by keeping the hoses and other RCD components away from the tension lines.

Installation of the RCD below the tension ring also increases the pressure rating of the MPD system by removing the slip joint, which has been the challenge in previous applications of MPD from floating vessels. Another technical hurdle that needed to be addressed was the need for the RCD to withstand tension. This was readily addressed by outfitting the BTR RCD with 21 ^1/4-in. x 10,000 psi top and bottom flanges.

Finally, placement of the RCD below the tension ring also required that the equipment and all its connections be able to withstand and operate while being submerged in seawater for an extended period of time. As a result, the connections on the BTR RCD stab plate were designed and rated for subsea use.

In 2010, the SeaShield series Model 7875 BTR became the industry’s first RCD to be installed on board a dynamically positioned drillship as an integral part of the riser. The success of this equipment and its application marks a significant point in the extension of MPD safety and operational enhancement capabilities into the high-risk, high-cost environment of deepwater drilling and specifically to drilling rigs that have dynamic positioning capabilities. More importantly, the successful deployment of the BTR RCD also positions MPD for further expansion into the territory of ultra-deepwater drilling (at water depths greater than 7,000 ft), especially when dynamically positioned drilling units are involved.

By Alexey Pavlov, Glenn-Ole Kaasa, Statoil Research Centre

Figure 1: In developing an automated MPD control system such as this, Statoil has focused on the development of two key parts of the control system – the hydraulic model and the choke controller.

Managed pressure drilling (MPD) is a technology that enables fast and accurate control of the pressure in the well during drilling and completion operations. This is achieved by sealing the annulus and diverting the mud outflow to a choke manifold. By opening or closing the choke, one can actively control the pressure at a desired location in the well.

The main benefit of MPD is that it enables drilling wells with narrow pressure margins that are undrillable with conventional technology. Additionally, MPD technology’s hydraulic models and measurements allow for flow and pressure conditions in the well to be monitored in an accurate manner, thus allowing for kick and loss situations to be detected at an early stage. Once detected, they can be handled quickly through active pressure regulation. This leads to reduction of nonproductive time.

All these benefits of MPD have been demonstrated by numerous successful MPD applications worldwide, both onshore and offshore. This may be perceived as a proof of maturity of MPD technology, which is indeed the case for manual MPD. Even though in the future we will definitely witness improvements of MPD hardware (e.g., annular seal and choke), they will neither change the essence of manual MPD operations nor significantly improve its efficiency. It is the human factor that to the largest extent limits the efficiency of manually controlled MPD.

For automated MPD, the situation is different. The automatic control system is the component that allows one to get the most out of the MPD hardware. The control system, which provides accurate pressure control in an automatic way, resembles to some extent an autopilot in an airplane. Still, the level of maturity of MPD control systems, compared with automatic control systems like the autopilot, is rather low. An autopilot can control the process of flying with very little attention from the pilot.

In many cases, the autopilot controls the airplane in a safer and more efficient way than pilots are able to do manually, and even landings in bad weather conditions are nowadays safer with autopilots. Despite all the complexity of modern airplanes, the operation of an autopilot is as simple as setting the desired course and flight parameters, and pressing an on/off button.

This simplicity of operation in combination with high safety and efficiency of autopilots is made possible due to advanced automatic control systems and is one of many examples that demonstrate the power of modern control solutions.

In comparison, an automated MPD system, even though equipped with an automatic control system, still requires a whole crew to operate it. It needs constant attention and adjustments (e.g., to update well and mud parameters that vary during drilling), and depends to a large degree on qualified manual interaction. This comparison leads to the conclusion that simplicity (or currently complexity) of MPD operations, as well as their efficiency, can be significantly improved by applying advanced automatic control solutions.

This conclusion motivated the development of an MPD control system in Statoil R&D, which started in 2007 with the goal to improve efficiency, safety and simplicity of MPD operations by intelligent automatic control solutions.

Following theoretical development and numerous simulations studies, the first version of this control system was successfully tested in full-scale experiments at a drilling test facility in Stavanger, Norway. Some components of the control system were also tested against field data from MPD operations in the North Sea. To present these results and the benefits of this control system, let’s first have a closer look at an MPD control system in general.

The main objective of an MPD control system is to maintain the pressure in the well, typically at the casing shoe or the bottom of the well, within the pore and fracture pressures. This is achieved by controlling the pressure to a specified value within these margins, which is determined in the operation planning phase. As shown in Figure 1, the control system consists of two parts:

• Hydraulic model,

• Choke controller.

Figure 2: An advanced choke controller was tested in experiments at a full-scale rig in Stavanger. This chart shows that the choke pressure p_c closely follows its reference value pRef_c with uniform performance.

The hydraulic model computes a reference value pRef_c for the backpressure (upstream the choke) needed to achieve the desired pressure pSP_dh in the well. This is done based on well parameters, top-side measurements and, when available, downhole measurements (received either through mud-pulse telemetry or a wired pipe). The choke controller automatically opens or closes the choke to bring the backpressure to the reference value generated by the hydraulic model.

In this way one can control the pressure in the desired location of the well. Efficiency, robustness and usability (i.e., how easy it is to operate the control system and how much attention it requires) of the overall control system depend primarily on the hydraulic model and the choke controller. Therefore, in the work of developing an MPD control system, our attention has been focused in particular on developing and improving these two parts of the control system.

Existing automated MPD systems are mostly based on conventional automatic control solutions developed for process industries, where processes are usually slow. Since pressure transients during drilling operations are typically much faster than in the process industry, these conventional control solutions are not particularly suited for MPD. Conventional proportional-integral (PI) controllers are reactive by nature. This means that a PI controller starts acting only after deviations of the backpressure from its desired value are observed. It does not take into account any other information, even though it may be available.

This limits the ability of the PI controller to compensate for fast changes in the operating conditions. This in turn impos es constraints on operations, such as ramping of rig pumps and tripping (surge and swab), which reduces the attainable efficiency of the operation. In addition to that, a PI controller has to be tuned for particular well conditions, such as mud compressibility, well length (volume), and pressure conditions. Significant changes, for example, in pressure conditions, which may occur in a critical situation, may result in poor performance or even instability of the control system.

The advanced choke control system developed by Statoil effectively utilizes available top-side measurements to compensate for changes in the operating conditions in a proactive way. It starts acting the moment operating conditions start changing and before the effect of this change becomes noticeable in the backpressure. The control system thus compensates for these changes more efficiently.

This enables, in particular, faster operations, such as faster ramping of the rig pump (e.g., reducing the connection time) and faster tripping (surge and swab) operations, while maintaining accurate pressure regulation. Moreover, the control system has uniform performance over the full range of pressures, which eliminates the need for re-tuning the controller for different pressure conditions. More importantly, this means that the control system provides reliable performance in case of large pressure variations, thus improving safety and handling of well control situations.

This control system may seem more vulnerable to the loss of measurements compared with a PI controller, which uses only the backpressure. Even if all the additional measurements used by the advanced controller are lost, it will lose only its proactive capabilities but retain its uniform performance, i.e., it will still perform better than the conventional PI controller.

Performance of the controller was tested in experiments at a full-scale drilling rig in Stavanger. Figure 2 shows test results with stepping reference value for the choke pressure (also known as backpressure) and demonstrates uniform performance in the pressure from 15 to 90 bar, which was the maximum allowed on the rig, without any re-tuning for different pressures.

Figure 3: In this simulated connection test, p_c was the choke pressure; pRef_c was the reference value for p_c from the hydraulic model; pHat_dh was the downhole pressure estimated by the hydraulic model; pSP_dh was the set point for downhole pressure; and q_p was the mud flow rate from the rig pump.

Similar tests performed with a PI controller tuned for 50 bar, demonstrated good performance in the pressure range from 40 to 60 bar, slow performance around 10 to 30 bar, and instability, i.e., violent oscillations resulting in control system shut down, around 80 bar.

The next test (Figure 3) emulates a connection scenario where the rig pump is ramped down from 1,000 l/min to zero flow, and then ramped up again to 1,000 l/min. The test was performed without a backpressure pump, which makes the task for the controller even more challenging. The figure illustrates excellent performance in the case with 60 sec ramping time (period from 0 sec to 200 sec in Figure 3) with 0.6 bar regulation error in steady-state (no flow conditions) and 1.9 bar peak regulation error.

A similar test was performed with a PI controller, resulting in 5.6 bar steady-state error. Clearly the advanced choke controller demonstrated much better performance than the PI controller. It demonstrated good performance even in an extreme connection test with 30-sec ramping time (see Figure 3, period from 200 sec to 350 sec), which resulted in the steady-state error of 1.9 bar and a peak error of 3.4 bar. The PI controller was not tested with 30 sec ramping time due to the poor performance observed in the 60 sec test.

Other tests with varying drillstring rotation (up to 150 rpm), surge and swab with 16 m/min block velocity, clearly demonstrated a superior performance of the advanced choke controller compared with the PI controller.

The hydraulic model is an essential part of an automated MPD control system. In many cases it is the limiting factor for achievable accuracy of the system. A lot of effort has therefore been put into developing advanced hydraulic models that capture all aspects of the drilling hydraulics. Such models are well suited for the planning phase of MPD operations. In real-time MPD, however, the main drawback of these models is the resulting complexity, which requires expert knowledge to set up and calibrate, making it a high-end solution with reduced usability.

In practice, much of the complexity does not contribute to improve the overall accuracy of the pressure estimate, simply because conditions in the well change during MPD operations, and because there are not enough measurements to keep all parameters of the advanced model calibrated. Moreover, the output of the hydraulic model is used by the choke controller and eventually by the choke actuator, which has its limitations in the opening/closing rate. Therefore, fast variations of this output, which result from some fine details of an advanced hydraulic model, eventually do not contribute to the overall accuracy of the pressure regulation. The choke does not simply compensate such fast variations.

To reduce the complexity of a hydraulic model while preserving accuracy, Statoil developed a simplified hydraulic model. This model, which is based on basic fluid dynamics, is able to capture the dominating hydraulics of an MPD system. Further, its simplicity (and therefore its very few parameters) enables its automatic online calibration. This is done by applying algorithms for online parameter estimation similar to those used in advanced control systems in the automotive and aerospace industry.

The resulting level of accuracy is comparable to that of a calibrated advanced hydraulic model (details on the hydraulic model can be found in IADC/SPE 143097, “Intelligent Estimation of Downhole Pressure Using a Simple Hydraulic Model,” by G. Kaasa, O.N. Stamnes, L. Imsland, O.M. Aamo).

Moreover, simplicity of the model is essential in analyzing its robustness. In a failure-critical application like MPD, all parts of the control system must be analyzed for performance in case of conditions diverting from normal operation. While complexity of an advanced model is prohibitive for such an analysis, it is possible for the simplified model.

Performance of the simplified model has been successfully tested against field data from MPD operations in the North Sea and during dedicated experiments at the full-scale drilling rig in Stavanger. Figure 4 illustrates performance of the hydraulic model for field data logged during MPD commissioning tests in the North Sea. In this case, uncertainty of the model is lumped into three parameters: θ_F, representing uncertainty in the friction model (both for the drillstring and annulus); θ_FA, representing uncertainty in the friction model in the annulus only; and the uncertainty in the mud density θ_ρ.

Figure 4: A simplified hydraulic model provided downhole pressure estimation with automatic calibration of model parameters.

In the figure, these uncertain parameters have been scaled such that they correspond to the correct value when they are equal to 1. In the hydraulic model with automatic calibration, θ_F and θ_ρ are updated based on the top-side measurements only. The calibration of the parameter θ_FA is based on PWD measurements when they are available.

In the case presented in Figure 4, the initial value of the mud density has been chosen 10% higher than its nominal value, and friction parameters have been chosen 50% higher than their nominal values. This results in the initial pressure overestimation by almost 30 bar.

Once the autocalibration functionality is activated, the uncertain parameters quickly converge to their nominal values and, as a result of that, the estimate of the downhole pressure converges to and stays on the actual downhole pressure (its measured values are shown in the upper plot of Figure 4). This example demonstrates excellent performance of the simplified hydraulic model with autocalibration even with such a significant initial offset in the uncertain parameters.

The advanced choke controller and the fit-for-purpose hydraulic model developed by Statoil clearly demonstrate the potential of advanced automatic control solutions in MPD. In fact, this establishes a trend for further development of MPD systems: higher efficiency, reliability and simplicity of operation achieved through advanced automatic control solutions. Following this trend, automated MPD operations in the relatively near future must be as simple and routine as flying an airplane with an autopilot.

As a part of the normal drilling operation, a driller will specify desired pressure parameters and activate a “drilling autopilot” – an intelligent automatic control system running the drilling process with full control of the well hydraulics and requiring attention from the driller only in exceptional situations. Numerous examples of successful applications of advanced control systems in other industries as well as in-depth academic studies and our own expertise and experience within control systems indicate that this is not just a vision, but a coming reality.

By Jeremy Cresswell, contributing editor

North Sea drilling analysts Hannon Westwood is forecasting nearly 350 exploration, appraisal and development wells over the next few years for the UKCS. “These are wells that are placed on our database when we know that they’re likely to be on the cards,” said analyst Andrew Vinall.

Warp back to the first few weeks of 2011 and it looked as if Northwest Europe was set for a vintage year, so long as oil prices remained robust and there were no “left-of-field balls” to contend with.

But that’s exactly what did happen, at least in the UK sector, thanks to a budget decision in March by the British Treasury to increase its North Sea tax take by a further 12%, with no concessions offered to gas, even though prices for this commodity were then and remain relatively depressed.

The impact has been dramatic, with more than $10 billion of capital projects put on hold thus far and operational programmes cut, including chopping step-out wells targeting pockets of hydrocarbons suddenly rendered subeconomic; and the decommissioning of some elderly infrastructure brought forward, including the Murchison platform operated by CNR.

However, elsewhere on the Northwest Europe Continental Shelf, it has been business as usual, with no nasty fiscal surprises dealt out by other governments garnering revenues from maritime hydrocarbons production. In that regard, the news outside the UK sector seems almost prosaic and certainly routine by comparison.

Among the best when it comes to building a forward picture of Northwest European offshore prospects is Andrew Vinall of North Sea drilling analysts Hannon Westwood, who particularly specialize in UKCS and Norwegian sector activities covering exploration, appraisal and development drilling.

Notwithstanding the potential damage that the 2011 UK budget has already and/or may inflict in the near to medium-term, Mr Vinall is optimistic about the outlook for drilling in the British sector of the North Sea.

“We’re forecasting nearly 350 wells on the UKCS over the next few years … that’s E, A & D, of which around 145 are development. These are wells that are placed on our database when we know that they’re likely to be on the cards. We regularly have 200 E&A wells in our database, some of which drop away because people can’t get funding for them,” Mr Vinall said. “But those that are JV (consortium)-funded tend to go ahead.”

The approximately 200 UK E&A wells currently forecast by Hannon Westwood is mainly for the Central North Sea, but with a growing proportion in West of Shetland. The Northern and Southern sectors of the North Sea are attracting much less interest, whereas West of England (Irish Sea) drilling is sporadic at best.

While the Central North Sea has grown in popularity over the past decade, what is the West of Shetland attraction, given how traditionally slow it has tended to be as an exploration province?

“Historically it used to be around 8%  to 10% of the total population (of wells drilled annually). But we’re now seeing a higher percentage of wells being planned for WoS … up 3% to 4% on the prior norm. That’s significant,” Mr Vinall said.

Fueling the interest is the recent run of apparently reasonable-sized gas and oil discoveries, though the long-running Lagavulin well has just been abandoned by Chevron as a dud – one that cost an estimated $270 million-plus to drill, which is a near-record for UK waters.

As for the Southern North Sea, where the Breagh and Cygnus gas discoveries now under development are of material value to the UK, the downside is commodity prices.

“The gas price has depressed most of the drilling in the Southern North Sea, and only those wells that need to be drilled are going ahead,” Mr Vinall said.

“In fact, we have on our database the same number of planned exploration and appraisal wells in the Southern North Sea as West of Shetland.”

Turning to the Northern North Sea, Mr Vinall reports that this area is currently enjoying a resurgence with about double the number of wells planned than for West of Shetland or Southern North Sea.

“That’s about 45 E&A wells for the Northern sector over the period 2011 through 2015. Then you can double that again (to 90) for the Central North Sea over the same period. Central has lately accounted for around 50% of the E&A total.”

The approximately 200 UKCS exploration and appraisal wells being forecast by Hannon Westwood for 2011-2015 are mainly for the Central North Sea, but with a growing proportion for West of Shetland. Drilling is sporadic West of Britain (Irish Sea). Natural gas prices have depressed drilling in the Southern North Sea, and the Northern North Sea is seeing a resurgence in drilling activity.

Brief reference was made earlier to the sporadic activity West of England; however, further south in what is known as the Celtic Sea, a number of wells are planned, with Irish company Providence Resources setting the pace.

“There’s a bunch of wells being drilled in the Celtic Sea in a bid to bring on some of the discoveries made in recent years, with one or more rigs scheduled for this year,” Mr Vinall said.

“And there were going to be some West of Ireland wells, but I believe most have been deferred out to 2012, partly because of the Eni assets sale and partly because Serica with RWE need to farm-out before drilling follow-up wells to existing discoveries.”

Eni’s early 2011 announcement that it was offering its entire Ireland exploration portfolio (preferably as a package) for sale could be interpreted as a set-back for a country where it has taken decades to achieve barely a handful of commercial oil and/or gas discoveries.

In particular, an interested operator or joint venture will have to assume the commitment of drilling a well on each of the Dunquin and Fiachra prospects. The former is regarded as one of the largest gas prospects ever identified on the Northwest Europe Continental Shelf.

Mr Vinall believes the Eni decision to get out of Ireland is not as negative as could be interpreted.

“It’s going to pick up out there because they’ve just had 15 companies apply for licenses. So I think we’ll see a burst of activity West of Ireland over the next two or three years and so perhaps further drilling.”

Turning to Norway, Mr Vinall said it is very much business as usual – long-term and underpinned by clearly articulated governmental strategy and fiscal stability.

Interestingly, last year and this, activity levels in the Norwegian sector are running higher than for the UK, and it looks as if that will continue. However, in terms of keeping an overall measure of that activity, the Hannon Westwood database count is showing 17 wells only … but these are just fully confirmed wells.

“There is quite a lot of farm-out activity going on at the moment, and this will lead to wells being drilled. And bear in mind, under the Norwegian fiscal system, one gets 80% of the tax back on the drilling of an exploration/appraisal well. There is no such incentive in the UK, other than for companies that already have production that they can offset the tax against.

Glenn White, general manager of Rowan Drilling UK and current chairman of the IADC North Sea Chapter, is just as positive about the Europe offshore scene as Mr Vinall. Not only that, the industry is armed with perhaps the best rigs that have ever been mustered in the North Sea as various newbuilds arrive. Those new tonnage investors include Rowan.

“We’re doubling in size in the UK in 2011,” Mr White said. We have three high-spec drilling units here and before the end of the year we will have doubled that to six. Our competitors are doing the same thing, and it means that the North Sea is going to have a lot of newer rigs and the older units will head elsewhere.

“The new units will meet today’s tougher safety standards, and the drive to replace rigs is coming from the industry itself, though cooperating closely with bodies such as Oil & Gas UK, IADC itself, together will the regulators and governments.”

Of course, if you’re an operator, the problem with high-grading the North Sea fleet is that rig owners will need higher dayrates. It might grate with some oil companies, but such investment is necessary and, ultimately, generally welcomed as the new rigs are bigger, better-equipped and safer.

According to Mr White, the CAPEX soaked up by the build, fitting out and commissioning of Rowan’s new North Sea trio is well over $1 billion.

“A dayrate of maybe $300,000 per day is needed just to cover the cost of a new unit over 10 to 12 years. We already had high-spec rigs in the North Sea, and we had pretty good term contracts.

“The rigs we use are relatively new … 12 years or younger and well-suited to drilling demanding wells such as HPHT. This has positioned Rowan in a good spot. Good times or bad, over the past 30 years we’ve never stopped building rigs at Rowan.

“We had the luxury of owning a rig builder that we just recently sold. Overall, we have seven new rigs coming out in 2011. Two of the three for Europe are already here; the other one will be here in September. They are the Rowan Viking, Rowan Stavanger and Rowan Norway.”

Does this mean that older, less able rigs no longer have a place in the North Sea?

“There sure is, especially for jackups in the Southern part of the North Sea. They might be 20 to 25 years old, but there’s still a place for them,” Mr White said.

But it’s not solely about drilling power in the North Sea. Big, high-spec jackups are also in demand to support the upgrading of existing platforms, development of new fields and to drill/produce them. The heavy crude Bentley field is an example.

It means that more beds are needed.

“Older rigs carry between 70 and 100 POB (persons on board); higher-spec ones can accommodate 120 to 150 and are easily upgradable to 180 to 200. You have to get a Gorilla-type rig or a CJ70 or an N-class. And we happen to own almost 50% of them,” Mr White added.

As for the long-running concern regarding rigs not yet having the freedom to cross between the UK and Norwegian sectors, his view is that while a common regulatory regime may never be possible, efforts continue to at least simplify the process.

“As drilling contractors, we of course want governments in Europe to work together and have a common level playing field where rigs have to comply with shared standards; that would benefit everyone,” Mr White said.

So does that mean everyone is inching towards a common agreement?

“I wouldn’t want to speculate on that. However, things are improving, signifi bodies such as Oil & Gas UK, IADC itself, together will the regulators and governments.”

KCA DEUTAG currently manages drilling operations on 20 platform rigs in Norway and the UK, with the former market being more sustained while the latter is more “go-stop-pause.” There’s also a refurbishment market in the UK, for example, with the extensive rig renewals on ExxonMobil’s Beryl Alpha and Bravo platforms.

Of course, if you’re an operator, the problem with high-grading the North Sea fleet is that rig owners will need higher dayrates. It might grate with some oil companies, but such investment is necessary and, ultimately, generally welcomed as the new rigs are bigger, better-equipped and safer.

According to Mr White, the CAPEX soaked up by the build, fitting out and commissioning of Rowan’s new North Sea trio is well over $1 billion.

“A dayrate of maybe $300,000 per day is needed just to cover the cost of a new unit over 10 to 12 years. We already had high-spec rigs in the North Sea, and we had pretty good term contracts.

“The rigs we use are relatively new … 12 years or younger and well-suited to drilling demanding wells such as HPHT. This has positioned Rowan in a good spot. Good times or bad, over the past 30 years we’ve never stopped building rigs at Rowan.

“We had the luxury of owning a rig builder that we just recently sold. Overall, we have seven new rigs coming out in 2011. Two of the three for Europe are already here; the other one will be here in September. They are the Rowan Viking, Rowan Stavanger and Rowan Norway.”

Does this mean that older, less able rigs no longer have a place in the North Sea?

“There sure is, especially for jackups in the Southern part of the North Sea. They might be 20 to 25 years old, but there’s still a place for them,” Mr White said.

But it’s not solely about drilling power in the North Sea. Big, high-spec jackups are also in demand to support the upgrading of existing platforms, development of new fields and to drill/produce them. The heavy crude Bentley field is an example.

It means that more beds are needed.

“Older rigs carry between 70 and 100 POB (persons on board); higher-spec ones can accommodate 120 to 150 and are easily upgradable to 180 to 200. You have to get a Gorilla-type rig or a CJ70 or an N-class. And we happen to own almost 50% of them,” Mr White added.

As for the long-running concern regarding rigs not yet having the freedom to cross between the UK and Norwegian sectors, his view is that while a common regulatory regime may never be possible, efforts continue to at least simplify the process.

“As drilling contractors, we of course want governments in Europe to work together and have a common level playing field where rigs have to comply with shared standards; that would benefit everyone,” Mr White said.

So does that mean everyone is inching towards a common agreement?

“I wouldn’t want to speculate on that. However, things are improving, signifi cantly and will continue to. It’s important to keep communicating … keep talking.”

Brian Taylor, chief operating officer for KCA DEUTAG, is bullish about the platform-based drilling market on the UKCS despite its maturity, and he sees a potential for 13 platform rigs there for his company. Mr Taylor also sees potential for renewing drilling packages aboard five or six UKCS drilling platforms.

KCA DEUTAG has been in the North Sea for decades and is a first-division platform drilling specialist in the Norwegian and UK sectors.

“Across those two sectors we’re currently managing drilling operations on 20 platform rigs; seven-ish in Norway  and 13-ish in the UK,” said chief operating officer Brian Taylor. Basically that means about a third of each market.

However, in the UK, platform-based drilling is a rather go-stop-pause business, while the approach in Norway is sustained … a pretty much continuous business for the Aberdeen-headquartered group’s drilling teams.

“In the UK, though we have the potential for 13 platform rigs, platform-based drilling on the UKCS is at more mature phase than Norway. At the moment the number of platform rigs currently working with our crews is around the five or six mark.”

Mr Taylor too is bullish about the market, describing it as “stable or better”; in other words, it still offers the potential to grow the business, despite the region’s growing maturity, albeit the aging process is less advanced in the Norwegian sector.

“Of course, Norway is dominated by one operator (Statoil) though others are clearly active there. In the UK, the shorter-term view plus greater maturity of the province means that operators have to prioritize their capital commitments, something that we at KCA DEUTAG understand.

“There is another aspect. We’re not just involved in drilling but also the refurbishing of many platform rigs. By example, in the UK sector, we’ve carried out extensive rig renewals on ExxonMobil’s Beryl Alpha and Bravo platforms.

“This sort of work’s becoming a feature of the North Sea, and we’re well positioned to do that. We have our own drilling facilities engineering division … RDS … and so we’re very keen to be involved in the upgrade and renewal of rigs.”

Mr Taylor currently sees the potential for renewing the drilling packages aboard another five or six UKCS platforms, but this depends on operators being willing to invest. Bearing in mind the latest UKCS tax rise, there is less incentive to spend in the North Sea; favored markets being expanding provinces like West Africa.

“There is competition for their CAPEX, and we fully understand that.”

So how many development wells was KCA DEUTAG responsible for in the North Sea in 2010?

“Around 35-40 … drilling or renewal of 35 to 40 wells on the UKCS compared with around 20 for the NCS,” Mr Taylor said.

“We expect about the same for the NCS this year too. On the UKCS the position has become less clear following the recent tax increase. However, it’s quite difficult to be sure that any reduction in the number of wells is the result of decisions around the UK fiscal regime.”

European drilling by the numbers

• $10 billion-plus in capital projects have been put on hold since a 12% increase in the UK’s North Sea tax take was put in place.
• Nearly 350 exploration, appraisal and development wells are currently forecast for the UKCS over the next few years, of which 145 are development.
• 45 E&A wells are currently forecast for the Northern North Sea for 2011 through 2015.
• 49% of UKCS E&A wells forecast for 2011 to 2015 are for the Central North Sea.

By Eirik Stueland, Talisman Energy; Matthew Spotkaeff, James Dolan and Christophe Dupuis, Schlumberger

Figure 1: Redevelopment plans for the Yme field offshore Norway included three vertical injectors and six high-angle producers. Located within the Egersund formation (marked on left), the optimal layers for the Yme development were the YS 4/5 and YS 7 sands.Figure 1: Redevelopment plans for the Yme field offshore Norway included three vertical injectors and six high-angle producers. Located within the Egersund formation (marked on left), the optimal layers for the Yme development were the YS 4/5 and YS 7 sands.

Today’s high oil prices, combined with new well geosteering technology, can make directional drilling a cost-effective option for revitalizing old oilfields previously considered uneconomical. One such case is the Yme field offshore Norway.

Originally developed by Statoil in the 1990s, this field produced 50 million barrels of oil between 1996 and 2001, with a plateau production of 40,000 bbl/day. The field was permanently shut down in May 2001 with an estimated overall recovery factor of 15% to 20%. Reasons for the shutdown included increasing water cut, high operating costs and relatively low oil prices at the time. The Yme field has since become the first abandoned field on the Norwegian Continental Shelf to be redeveloped.

Talisman Energy Norge submitted a plan for redeveloping the Yme field in 2006, and the drilling campaign – aimed at producing an additional 70 million barrels of oil – started in 2008. The plan included three vertical injectors and six high-angle producers with long (1,000-1,500 m) sections within the vertically thin (2-6 m; 10-20 ft) Callovian/Kimmeridgian-age Egersund formation inner estuary reservoir sands (Figure 1). The producers needed to be geosteered to maximize exposure of the targeted reservoir zones.

To delay water entry for as long as possible, the wells were to be drilled in a narrow corridor up-dip between existing watered-out producer wells and the field bounding fault. In addition, wells needed to be placed on the correct side of the bounding fault, as drilling into the unstable shale on the other side would require a sidetrack.

In 2010, Talisman planned to drill its final horizontal development well: a sidetrack targeting a high-permeability sand not sufficiently drained by other wells. The drilling team not only needed to keep the wellbore within a vertically narrow reservoir but also had to cope with restrictive lateral tolerance for well placement. The sidetrack had to twin much of the original well path, which had intersected the field’s major fault – the reason why this part of the target reservoir remained undrained. The borehole would have anti-collision issues with three offset wells. In addition, the thickness and dip of the formation in the area were uncertain. Thus the pre-drill structural model was not accurate enough for precise well placement.

Finally, subseismic faults had been encountered in previous wells, causing temporary losses of stratigraphic control. The challenge, therefore, was to drill the hole between the fault, mother bore and previous producing wells, identify the target sand, and then geosteer within it for at least 400-m MD – despite all the uncertainties and potential surprises.

Figure 2: Real-time DTB technology was used to map formation density in an area of high apparent dip. At 3,765-m MD, a conductive zone (darkest color on the inversion) was detected below and interpreted as water-flooded sandstone. The interpretation was confirmed with conventional LWD logs. Once in the sand below the water zone, the mapping of the fluid contact remained consistent.

Detailed pre-job analysis of the drilling, anti-collision and geosteering challenges led to the reliance on two key well placement logging-while-drilling (LWD) technologies with the rotary steerable system (RSS) in the bottomhole assembly (BHA). A Schlumberger well placement team contributed to pre-job planning, real-time operations support and post drilling analysis.

The PeriScope real-time bed boundary mapper tool was used to map the structure around the wellbore to help identify individual sand and intra-shale units while drilling and to help geosteer the horizontal section within the high-permeability pay zone. This deep azimuthal electromagnetic resistivity LWD system makes 360° deep directional measurements that can indicate the distance to, and orientation of, formation boundaries from the borehole, using a combination of tilted coil technology and multiple frequencies and spacings.

During drilling operations, the LWD measurements are transmitted in real time to the surface. The tool is sensitive to contrasts in resistivity within a radius of investigation that varies depending on the particular geological environment.

In the case of the Yme reservoir, distance-to-boundary (DTB) measurements were possible within 4 m (12 ft). The resistivity contrasts can be due to changes in lithology (e.g., sand versus shale) or fluid changes, such as an oil-water contact. The tool’s deep directional measurements provide considerably more information than is possible when using conventional LWD systems in low-measurement-contrast reservoirs. These unique symmetrized directional measurements, with maximum sensitivity to formation or fluid boundaries, enable 3D mapping of resistivity boundaries around the wellbore in real time.

Geologists expected the structure to roll over and dip steeply toward the major fault shortly after the sidetrack entered the target reservoir. The EcoScope multifunction LWD service was employed to provide additional structural dip information to help stay on track and update the pre-drill model during geosteering operations. This service integrates formation evaluation, well placement and drilling optimization measurements into one collar. Besides resistivity, neutron porosity, and azimuthal gamma ray and density, the service offers the first commercial LWD measurements of elemental capture spectroscopy and sigma. The tool is also the first to offer commercial LWD nuclear measurement of formation density without chemical radioactive sources.

In any field redevelopment project, water fronts and water fingering are to be expected, and the key to producing efficiently is to understand the fluid distribution. However, in this case, prior knowledge of the fluid distribution was insufficient to predict the dynamics of fluid substitution, so design of the geosteering campaign included measuring, mapping and managing those events as they arose. One of the uses of the bed boundary mapper technology was to define water zones while drilling the producers.

Figure 2 is a real-time geosteering display that shows one of the water zones mapped while drilling one of the producers. Excellent reservoir sand was entered at 3,740-m MD. The apparent structural dip indicated by the DTB inversion was 9°. This was confirmed by dip-picking on the density borehole image. At 3,765 m, a conductive bed is clearly seen from 3 m below the wellbore. This was interpreted as a water-flood zone in the most permeable part of the reservoir.

Figure 3: A PeriScope DTB panel showing the real-time well trajectory through the target reservoir (red) compared with the planned well path (green), and indicating distances (small squares) from the overlying low-permeability zone.

It was decided to drill through it – partly to confirm the hypothesis of water but also because the redevelopment strategy recommended that the wellbores cross as many sand layers as possible rather than drilling within a single layer.

The conventional LWD logs and the DTB inversion around 3,800-m MD confirmed that the observed conductive body was indeed water. After drilling another 40 m, the wellbore exited the water zone and subsequently mapped it 2-m true vertical depth (TVD) above for more than 100-m MD. The well trajectory continued up-structure, and after 3,900-m MD crossed back into the upper part of the sand layer. The tool response clearly indicated that the water zone does not extend to that part of the reservoir.

During the geosteering process, real-time DTB measurements were consistently able to image water-fingering zones within the high-permeability target sands. This capability enabled placement of wells within the thin productive zones and gave the subsurface team a way to visualize the water flooding.

Schlumberger LWD specialists worked on the rig alongside Talisman wellsite geologists, while well placement engineers provided 24/7 support to the company’s operations geologist and G&G subsurface team onshore Norway. Real-time drilling data, combined with directional drilling experts – both onshore and offshore – successfully avoided collision issues with the other wells.

Prior to landing the wellbore in the target reservoir, the LWD density-neutron measurements enabled geologists to identify an additional 400 m of very good quality reservoir in the upper section of the underlying sand.

Figure 4: Advanced processing of the DTB mapping LWD data provided valuable information to refine the structural model for post-well evaluation.

Once inside the target interval, a relative lack of heterogeneity made it tough to determine the structural dip with either of the two LWD tools alone. Combining information from both, however, proved effective and showed that the pre-drill model had been inaccurate. Steepening due to rollover did not occur as much as predicted, and the model was updated accordingly in real time.

Had the actual path followed the planned trajectory, the well could have remained within the overlying low-permeability interval for its entire length (Figure 3). Instead, the geosteered wellbore reached a total distance of 511-m MD within the target sand – exceeding its objective by more than 100 m and achieving a net-to-gross ratio of 92.5%. In addition, the well remained between 0.7 and 2.2 m TVD of the upper boundary, enabling Talisman to maximize production of attic oil.

After drilling, Petrel ribbon surfaces were created, derived from advanced processing of the bed boundary mapper measurements (Figure 4). These surfaces are representations of all formation boundaries detected within the tools’ range. This was a milestone in the use of such real-time LWD imaging data, as in addition to helping geosteering of the wells, better mapping of actual surfaces can refine structural surfaces and fluid distribution in the fieldwide geological model, increasing confidence in drilling decisions for future wells. Successful well placement was the result of the Talisman G&G team’s knowledge and Schlumberger well placement expertise in making geosteering decisions using real-time LWD data.

A total of 34 fatalities were reported in 2010, a 0.014 fatality incidence rate. That’s down from 2009’s 0.015.

The drilling industry lost some ground in 2010 when it came to its lost-time incidence (LTI), recordable incidence and fatality rates, according to the newest IADC Incident Statistics Program (ISP) report.

Last year, the industry’s worldwide LTI numbers moved from 2009’s record low of 0.37 up to 0.38, worsening by 3%. The recordables rates moved up from 1.22 to 1.31, which is 7% worse than the 2009 report of 1.22.

The number of fatalities rose from 32 to 34 last year; however, the 2010 fatality incidence rate declined to 0.014, compared with 0.015 in 2009.

Looking at the longer-term trend, the industry’s efforts toward safety have resulted in the occupational LTI rate falling from more than 14.00 in 1963 to 0.38 in 2010, which is a 38-fold improvement.

A total of 111 contractors, representing approximately 78% of the worldwide oil and gas well drilling rig fleet, participated in the 2010 ISP, which has tracked safety and accident information for the drilling industry since 1962. Data here account for 459.391 million manhours worked, during which a total of 846 LTIs and 3,010 recordable incidents were reported.

As with previous years, in 2010 the floorman position suffered the largest percentage of lost-time injuries and recordable incidents.

Incidence rates are calculated on incidents per 200,000 manhours. Data are compiled separately for land and offshore operations and for eight geographic regions — US, Europe, Canada, Africa, Middle East, Asia Pacific, Central America/Caribbean, and South America.

A total of 34 fatalities were reported in 2010; the incidence rate was 0.014, compared with 2009’s 0.015. Employees with one to five years of service with the company accounted for 15 fatalities, the largest percentage. Twelve fatalities occurred to employees who had less than six months of service, and three had between six months and a year of service. Two of the victims had worked for the company between five to 10 years and one victim had worked for the company for 10 years or more.

Fingers are still the most vulnerable part of the body, statistics show.

Five fatalities occurred during rigging up or down operations. Ten of the fatalities involved “struck by” incidents while six involved “caught between” incidents. Eight of the fatalities occurred to floormen; 11 were supervisors of drillers or above.

Contractors in the European land and offshore categories together worked more than 62.14 million manhours in 2010 with no fatalities. Within this category, offshore workers accounted for 30.71 million manhours while land had 31.43 million manhours.

“Caught between” incidents accounted for the most LTI and recordable injuries and was closely followed by “struck by” injuries.

US land and offshore contractors together worked more than 118.44 million manhours and reported a total of 22 fatalities. Onshore operations accounted for 84.54 million manhours worked with 13 fatalities while offshore contractors worked 33.9 million manhours and reported nine fatalities.

Canadian contractors accounted for 3.3 million manhours and no fatalities. In this region, land workers reported 2.27 million manhours while offshore workers reported 1.06 million manhours.

The Central America and Caribbean  region accounted for 11.75 million manhours altogether with one fatality. Land operations reported 7.45 million manhours and one fatal incident while offshore operations reported 4.3 million manhours and no fatality.

“Pipes/tubulars” is the equipment category responsible for the most LTI and recordable incidents.

Africa combined land and offshore accounted for 56.47 million manhours with three fatalities. Onshore operations reported 30.39 million manhours with three fatalities while offshore had 26.08 million manhours and no fatalities.

The Middle East region accounted for 97.63 million manhours with three fatal incidents. The land division had 67.31 million manhours and two fatalities, and there were 30.32 million manhours and one fatality for the offshore division.

Asia Pacific accounted for 53.51 million manhours and two fatalities. Offshore had 36.98 million manhours with two fatalities while the land division had 16.52 million manhours and no fatality.

South America made up 56.13 million manhours with three fatalities. Land operations had 33.31 million manhours and one fatality while offshore had 22.82 million manhours and two fatalities.

By activity, “tripping in/out” is the operation that involves the most LTI and recordable injuries and is followed closely by “rig up/down” and “rig repairs.”

One of the best improvements year-on-year was in the offshore LTI rate for the Asia Pacific region, which went down 45% from 0.29 in 2009 to 0.16 in 2010. The region’s recordables rate also improved 20% from 0.84 in 2009 to 0.67 in 2010.

European statistics also saw significant improvement, both onshore and offshore. Land workers saw their LTI rate improve 33% from 0.33 for 2009 to 0.22 for 2010, while their recordables rate improved 34% from 0.47 to 0.31. Offshore, the LTI rate was shaved by 30% from 0.30 to 0.21. Recordable incident rates worsened slightly to 0.74.

In 2009, Middle East land had an LTI rate of 0.23, which improved 22% to 0.18 in 2010. Their 2009 recordable incidence rate of 0.91 improved 5% to 0.86 in 2010. However, offshore the LTI rate worsened 53% from 0.15 in 2009 to 0.23 in 2010 and their recordable incidence rate also worsened 17% from 0.66 in 2009 to 0.77 in 2010.

As with past years, by far the most injuries in drilling operations occurred on the rig floor.

The Africa onshore LTI rate for 2009 was 0.43, and that improved 9% to 0.39 for 2010 while their recordable incidence rate improved by 23% from 1.50 in 2009 to 1.16 in 2010. Offshore workers in this region saw a worsening in their LTI rate by 25% from 0.20 in 2009 to 0.25 for 2010. The offshore recordable incidence rate also worsened, by 12% from 0.81 in 2009 to 0.91 in 2010.

The LTI among US offshore workers worsened by 20% from 0.20 in 2009 to 0.24 in 2010 while the total recordable incidence rate improved slightly from 0.87 in 2009 to 0.86 in 2010. US land workers’ LTI rate worsened 10% from 0.93 in 2009 to 1.02 in 2010 and their recordable incidence rate worsened 12% from 3.07 in 2009 to 3.44 in 2010.

Employees with between one and five years of service had the highest number of LTIs and recordables, followed by those with six months to one year of service.

Canada land’s LTI rate worsened by 82%, going from 0.19 in 2009 to 0.35 in 2010. Their recordable incidence rate worsened 118% from 1.05 in 2009 to 2.29 for 2010. Offshore, Canadian workers saw their 2009 LTI rate of zero worsen to 0.19 for 2010 and their recordable incidence rate of 0.94 for 2009 worsen 21% to 1.14 for 2010.

In the Central America and Caribbean region, the onshore 2010 LTI rate was 0.48 and the recordable incidence rate was 0.89. Central America and Caribbean offshore had an LTI rate of 0.05 and a recordable incidence rate of 0.42 for 2010.

09:00-16:00 hours was the leading category in lost-time injuries and recordable incidents by time of day.

South America land had an LTI rate of 0.23 and a recordable incidence rate of 0.94 while South America offshore saw a 2010 LTI rate of 0.39 and a recordable incidence rate of 1.03.

•   By occupation, the floorman position suffered the largest percentage of injuries, similar to previous years.
•   By body part, fingers remained the most vulnerable part of the body.
•   By incident type, “caught between” accounted for the most incidents and was closely followed by “struck by” injuries.
•   By equipment, pipes/tubulars was the equipment category responsible for the most LTIs and recordable incidents.
•   By activity, tripping in/out involved the most lost-time and recordable injuries.
•   By location, by far the most injuries in drilling operations occurred on the rig floor.
•   By time in service, employees with between one to five years of service had the most LTIs and recordables, followed by employees with six months to one year of service.
•   By time of day, the most LTI and recordable incidents occurred between 09:00 to 16:00 hours.
•   By month, June accounted for the most LTIs while August accounted for the most recordables.

By month, June accounted for the most LTIs while August accounted for the most recordable incidents.

Incidents occur in many places around the rig and to all crew members. Incident data are analyzed by occupation, body part, incident type, equipment type, operation, location time in service, and time of day the incident occurred.

For more information about the IADC Incident Statistics Program or to participate in this program, please contact IADC regional vice president North America and lead staff land HSE issues Joe Hurt at +1/713-292-1945 or joe.hurt@iadc.org. Additional information can also be found online at the IADC website at www.iadc.org/asp.htm.

2010 Incident statistics report: How the industry performed

• 315 floormen suffered lost-time incidents out of a total 846 incidents reported.
• Out of 847 LTIs, 170 fingers were reported as injured.
• More than 870 recordable incidents out of a total of 3,010 incidents were in the “caught between” category.
• 398 recordable incidents out of a total 3,010 were attributed to the pipes/tubulars equipment category.
• 298 LTIs occurred on the rig floor out of 847.
• Out of 847 incidents, 145 LTIs occurred while tripping in/out.

Matt Ralls, IADC 2011 chairman

In January this year, the National Commission on the Gulf of Mexico oil spill released its report along with several recommendations for changes to the oversight of offshore operations relating to both safety and protection of the environment. The commission recommended that the industry create its own oversight agency, independent of any groups with lobbying activities, that it create a safety management system based on the safety case approach used by several North Sea countries, and that it have a system of independent audits for verification of compliance.

In early March, IADC Executive Committee members hosted a meeting and dinner with several European members of the International Regulators Forum. During the open forum discussion, one of the regulators challenged industry participants with his observation that the offshore drilling industry did not have a culture of safety.  In an impassioned response, several industry participants flatly disputed that claim and offered numerous examples of the significant strides that have been made in improving safety in offshore operations.

The regulators appeared to accept what was said, and the conversation moved to another topic where industry participants had less to say. The question raised by the regulators was, “What new systems or processes was the industry offering, then some 10 months following the tragedy in the Gulf of Mexico, to buttress safety oversight in the offshore industry?” The uneasy silence that followed the question was ended by a general comment on task forces and study groups and an implicit admission that the industry itself had not yet come up with any substantive changes to the safety processes in the Gulf of Mexico. That was about to change.

On 18 March, the American Petroleum Institute (API) announced plans to establish the Center for Offshore Safety (COS), and in early June, leaders of the COS Working Group held an informational meeting to introduce the center to a wide audience of operators, contractors and service companies. Based in Houston, the COS is expected to be up and running by the end of the summer and will be responsive to many of the recommendations of the National Commission.

A key objective of the new center will be to assist member companies in their implementation of API Recommended Practice 75, which relates to safety and environmental management systems (SEMS). Long voluntary in the US, compliance with RP 75 has now been mandated by way of new regulations that will go into effect in November this year.

Participation in the COS will be mandatory for API member companies with deepwater operations (greater than 1,000 ft), and participating company CEOs will be required to endorse the philosophies espoused by the COS. Participating companies will be required to share information on significant incidents and undergo third-party audits of compliance with their safety systems in order to attain certification. Safety statistics will be collected and compiled by the COS to document the industry’s progress on improving the safety of offshore operations.

Companies that fail to meet COS standards will be required to take steps to remediate deficiencies or risk potentially severe implications for their ability to work for other API member companies.

As this new system of self-regulation is rolled out, there will understandably be concerns on the part of contractors and service companies on several levels. What degree of detail, by company, will be made public or available to API member companies? What will be the process for disputing unfavorable audit findings, or the timing for remediating noncompliance? Will the major oil companies, who largely determine API policy, eventually expand the requirement for COS membership beyond just deepwater activities or US waters in order to work for them? How will this system be coordinated with the existing regulatory framework and will it meet the objectives of the US Department of Interior and its new Safety Advisory Committee in terms of strengthening safety practices in the offshore industry?

These questions are being addressed, and the whole creative process is being watched with interest by, and possibly implications for, the regulators for other offshore industries around the world.

In my opinion, the development of the COS and its administration under the auspices of the API’s separately funded and highly respected standards and certifications arm is an appropriate and necessary response by our industry to ensure changes are made in safety oversight following the tragic events of last year. Despite the initial objections of the National Commission, there is no other industry association with the scale, resources and influence to make a new system like this successful and sustainable.

The COS Working Group has been thoughtful and thorough in its approach to the structure of the COS and very responsive to the concerns of the contractor and service company members as to the complexities and burdens of how it will be put into practice. The COS will be governed by a board comprised of representatives from operators, contractors, service companies and trade associations, including, importantly, the IADC.

Over several decades and tens of thousands of well drilled, the offshore industry in the US has had one of the best records for safety and environmental responsibility of any industry in the country. But still Macondo happened, and tempting as it might be to refer to it as an outlier and point to the industry’s favorable statistics, we must embrace the need for substantive change to our safety processes to ensure it never happens again.

It is vital that we collectively work to restore public confidence in our industry’s safety and environmental performance – we operate in US waters at the pleasure of the citizens of this country, and we have to continually earn that right with the safe and successful completion of every well drilled. It’s our moral obligation to the people who work for us, and failure would be a threat to the viability of this industry.

IADC president Dr Lee Hunt (second from right) hosted Cuban oil and gas sector representatives and experts at the 2011 IADC Environmental Conference in Trinidad: (from left) Jorge Pinon, Florida International University; Juan Fleites, Cubapetroleo; Dan Whittle, Cuba Environmental Defense Fund; Fidel Ilizastigui Perez, Cuba’s Office for the Environment and Nuclear Safety Regulation; Humberto Rivero, ambassador of the Republic of Cuba in Trinidad and Tobago; Eredio Puente Gonzalez, Cubapetroleo; Ulises Fernandez Gomez, Cuba’s Office for the Environment and Nuclear Safety Regulation; Dr Hunt; and Dr Manuel Marrero, Exclusive Economic Zone of Cuba Commission in the Gulf of Mexico.

IADC achieved a safety landmark in May when it gathered industry experts and specialists from around the world, including Cuba and the Bahamas, to begin a critical dialogue on personnel and system safety in oil and gas operations in the Gulf of Mexico and Caribbean.  “The fact that Cuba will begin exploration this year in ultra-deepwater has raised concern about safety precautions. The sharing of industry best safety and environmental practices that occurred during the conference underscored the need for all countries that border on the GOM – Cuba, Mexico and the US – to have access to all resources that exist in case of an emergency,” IADC president Dr Lee Hunt said.

The 2011 IADC Environmental Conference & Exhibition was held in Port of Spain, Trinidad, 12-13 May, and featured a discussion of a “One Gulf” concept (in which all countries bordering the GOM interact), an overview of sixth-generation rig capabilities, a presentation on the environmental aspects of drilling project financing, and the industry’s ability to explore, drill and produce safely in sensitive marine environments.

Presenters included Fidel Ilizastigui Perez, process safety and risk management specialist for Cuba’s Office for the Environment and Nuclear Safety Regulation; Jorge Pinon, professor at the Florida International University and an expert on Cuba’s energy sector; Ilidio Franco dos Santos, environmental engineer for Sonangol; Richard McLaughlin, endowed professor chair for marine policy and law for Texas A&M University Harte Research Institute  for Gulf of Mexico Studies; and Moya Crawford, managing director for Deep Tek, a member of the Emergency Subsea Response Alliance.

Mr Perez noted that in the early days of Cuban exploration, a number of international standards had been reviewed and Cuba decided to base its safety practices on standards set in Britain. Cuban standards evolved and the IADC HSE Case Guidelines for Mobile Offshore Drilling Units were incorporated. In 2009, new regulations were issued requiring companies to present a safety case for all major hazards. The IADC HSE case will be used to obtain an environmental license.

“For us the common goal and common challenge is to think about how to prevent accidents from happening, to understand the root cause of an accident and be able to prevent it. It’s important to understand that safety culture leads the way,” Mr Perez said.

Mr Pinon pointed out that the US embargo against Cuba would make it impossible for the energy industry to send any equipment to Cuba in the event of a spill, leaving the GOM vulnerable. “The US needs to bring Cuba into the conversation and bring Cuba to the table to talk about that so in the case of a national emergency, Cuba has access to all of the resources it needs.”

Last year, an IADC delegation was granted a travel license to Cuba to discuss safety and mitigation of environmental hazards with Cuban authorities. The IADC delegation consisted of Dr Hunt; Brian Petty, executive vice president for government affairs; Steve Kropla, group vice president of operations and accreditation; Alan Spackman, vice president for offshore technical and regulatory affairs; and Paul Kelly, president of the Gulf of Mexico Foundation. In addition to obtaining an overview of the prospect for deepwater drilling offshore Cuba, the IADC delegation briefed Cuban authorities on global drilling standards and best practices, environmental protection, safety procedures, hurricane preparation and personnel training.

Regarding the conference, presenter Dan Whittle, senior attorney and director of the Cuba Program Environmental Defense Fund, commented, “IADC has done something that no one else has done and that is to get people to talk outside of Cuba in a very constructive and serious way about how we can begin to work together. After today, I think this constructive dialogue has to continue.”

Petroleum engineering students from the University of Trinidad and Tobago attended the 2011 IADC Environmental Conference & Exhibition in early May. IADC extended an invitation to 45 students to absorb the real-world input on environmental conditions and energy development in the Gulf of Mexico.

When Stephanie Liddelow, a petroleum engineering student from the University of Trinidad and Tobago (UTT), took her seat in the conference room of the Hyatt Regency in Port of Spain, Trinidad, on 12 May, she did not know quite what to expect. Ms Liddelow was one of 45 students invited to attend the 2011 IADC Environmental Conference & Exhibition, held 12-13 May.

As the day’s presentations unfolded, she found herself looking through a window to the future framed by scientific experts and professionals from the myriad disciplines connected with the global oil and gas industry. Student attendance at the conference had been sanctioned by Rodney Jagai, UTT department head and program professor.

Moya Crawford, managing director for Deep Tek, noted that the conference was a well organized and informative event and believes IADC can be doubly congratulated, “firstly, on facilitating the Cuban delegation – a tremendous amount of work had obviously gone into that – and secondly, for having so many young people just starting off in the oil and gas industry there. Both were very far-sighted achievements.”

The UTT petroleum engineering department believed that the conference would reaffirm the importance of environmental issues to the petroleum industry. In the drilling and completions courses at the school, environmental awareness of discharges and effluents are always a part of the discussions, particularly as it relates to drilling mud and well control, according to Doodnath Ramsundar, research associate and lecturer at UTT.

Beaming as she emerged from the conference hall, Ms Liddelow stopped to comment that she had wished to step up to the microphone and thank Dr Lee Hunt, IADC president, for inviting UTT students. “I thought it was a very educational experience for me, this being my fourth year at the university,” she said. “It was very interesting to actually meet these people and hear their thoughts, what they had to say about the oil industry and the environment and what’s happened. I was moved. I will be part of the generation that will be going into the oil and gas industry now. The industry may actually finish the work that it has started (to partner with other energy players in the Gulf of Mexico and Caribbean region to set and meet necessary environmental standards). That’s inspired me, and I can speak for my classmates as well, to continue (the environmental initiative) that’s been started.”

Expressing a similar reaction to the environmental conference experience, student Stefan Joseph said, “It was a great experience for me, a student and an aspiring petroleum engineering major, to be surrounded by great established professionals. The conference opened my eyes on how important the environment is with respect to the petroleum industry. It also raised my awareness to many of the challenges faced in drilling and the petroleum industry.”

University of Trinidad and Tobago petroleum engineering students (from left) Joshua Ragoonanan, Stephan Joseph and Khalid Juman commented that attending the IADC Environmental Conference & Exhibition raised their awareness of the importance of the environment with respect to the petroleum industry.

Several students remarked that they were affected by a slide from one presentation that showed several children playing on a beach. The concept that these children represented the grandchildren of generations to come seemed to evoke and renew the students’ commitment to considering the environment while pursuing their interest in energy industry technologies.

“We hope to get information about environmental factors in drilling and the operations of contractors in the field, as well as hear about things that are being done to protect the future and how vetted technology can provide protection for the environment, as well as human life from pollution and environmental factors,” Joshua Ragoonanan, another UTT student, said.

“Since the entire thing is mostly about environmental concerns of the petroleum industry, I think that by being here and learning about the different technologies and systems that are in place … will help us to have some kind of faith that we will be protected offshore,” student Omari Waldron said. “We’re learning about sustainable development and how we have to provide for our future.”

“I would agree,” fellow student Khalid Juman said. “When I started to pursue petroleum engineering, I didn’t really think much about the environment to be quite honest, and today I realize that the environment has a lot to do with what I am doing. I think this information can help me out by offering a different perspective to my studies.”

Enthusiastic about the invitation to participate in the conference, student Kaleem Mohammed pointed out that “it was kind of a shock at first. We didn’t expect to get invited to something like this. It was quite an honor to be invited also, to be among petroleum engineers and the industry, which will be beneficial to us in some way with our studies. It’s a great exposure for us so we will know what we are getting into.”

“It was a real experience that the class was not expecting. When we got the e-mail, I was shocked to get this from the IADC. We’re still in school, in fact I’m glad to be here,” student Shannon Fernandez said.

Ms Liddelow and many of the other students attending the conference will soon be stepping into global energy careers. It is the hope of Dr Hunt, Mr Jagai and industry professionals that this next generation of petroleum engineers will fervently embrace the concepts presented at the conference to protect the Gulf, leaving a legacy of environmental responsibility.