Schlumberger’s Ian Falconer, marketing and technology manager, introduced technologies, such as the slim-hole PowerDrive Archer rotary steerable system and the Stinger conical diamond technology, at the 2013 SPE/IADC Drilling Conference, 5-7 March in Amsterdam. Starting with the drill bit, the new technologies are a part of the company’s integrated drilling system approach.

Sven Haberer, Baker Hughes, said the idea behind the Smart Flowback Fingerprinting technology is to remove human bias and make the process of detecting kicks and lost-circulation events as automated as possible.

By Katie Mazerov, contributing editor

An automated flowback monitoring technology has been developed to detect well kicks and lost-circulation events earlier than conventional manual methods and to generate an alarm alerting drillers and drilling engineers to take appropriate action. A case study, SPE/IADC 163474, describing how the Smart Flowback Fingerprinting technology was developed and deployed in a field test, was presented by Sven M. Haberer, Baker Hughes, at the 2013 SPE/IADC Drilling Conference and Exhibition in Amsterdam this week.

“Macondo clearly demonstrated how kick can affect the safety of people and the environment,” Mr Haberer said. “But kick is also one of the major causes of nonproductive time (NPT).” Deepwater studies have shown that NPT related to kicks and lost-circulation events can amount to 4.5% of the total well construction time, he added. For a 90-day well at a spread rate of US $1 million/day, that would translate to an estimated $4 million.

Kicks frequently occur during drill pipe connections, and flowback fingerprinting, or monitoring changes in mud pit volume, has been the method most commonly used for more than a decade to detect such events. Less common detection methods are mud return flow (flow meters) and standpipe pressure.

“Currently, the industry uses a manual alarm system that relies heavily on the experience and intuition of the engineer performing this critical safety monitoring task,” Mr Haberer said. “And, as with any manual system, anything that can go wrong, will go wrong. The idea behind this new system is to make the kick detection more intuitive, self-adjusting and as automated as possible to remove the human bias.”

Removing the guesswork

The Smart Flowback Fingerprinting technology uses statistical analysis to interpret flowback data during connections, taking the guesswork out of this critical task by completely automating kick/loss detection. The system generates intelligent alarms based on current well conditions, so kicks can be detected up to one connection earlier than with conventional methods.

“The system ensures that flowbacks exceeding normal volumes are always detected in real time, without human intervention, and also minimizes false alarms,” Mr Haberer explained. “It also automatically generates threshold and alarm curves based on statistical analysis of previous flowback profiles.”

As part of the field test, the system was tested against both real-time surface data and archived databases from other wells that had experienced events, such as influxes and mud losses. This was done to refine the methodology to take into account such factors as flowback exclusion – instances where pumps were turned off briefly or operating at a low rate.

No kick or well control incidents were detected during the field trial. In order for the technology to be fully commercialized, a number of areas are being enhanced. These include the development of new algorithms to account for rig heave on the surface pits being measured to avoid false positives at the beginning of the flowback cycle. Tools for displaying real-time drilling data during remote collaboration also are being developed.

“As deepwater wells become more complex, pressure-related problems such as influxes, wellbore breathing or losses also will become more challenging,” Mr Haberer said. “We are confident the Smart Flowback Fingerprinting will be another tool in our toolbox of intelligent systems that will detect kicks early, prevent NPT and increase safety.”

Tony Pink, vice president of drilling automation applications for National Oilwell Varco (NOV), speaks with Drilling Contractor associate editor Katherine Scott at the 2013 SPE/IADC Drilling Conference in Amsterdam on 6 March. Mr Pink discussed the company’s NOVA initiative, which NOV considers the next generation in drilling controls and automation. Integrated within operating systems, NOVA drives well execution plans from a single source, executing automatic control and connection to drill and to respond to the well. The open-platform concept allows for greater customization. NOVA was launched at OTC last year.

Click here to read more about NOVA and other drilling automation technologies.

Individual machines working separately and as one unit will make up a fully autonomous drilling system, monitored by humans through a capable man-machine interface, Kenneth Søndervik, Robotic Drilling Systems, said at the 2013 SPE/IADC Drilling Conference & Exhibition in Amsterdam.

By Joanne Liou, associate editor

In the realm of automation, the best potential for enhanced HSE and cost savings will be achieved through multiple robotic machines that are able to act as independent units or as a stand-alone machine, Kenneth Søndervik, Robotic Drilling Systems, said at the 2013 SPE/IADC Drilling Conference & Exhibition this week in Amsterdam. In presenting SPE/IADC 163466, Mr Søndervik said that he envisions autonomous robotic drilling completely removing people from the drill floor. A test rig running the company’s robotic system in Stavanger, Norway, has demonstrated fully autonomous tripping. While “one machine holds the drill pipe, it will tell the other machine, ‘I’m holding it.’ When the second machine has it, it will tell the first machine, ‘I’m holding it, now.’ All machines will work independently of each other, as well as a group,” he explained. “While one machine is tripping in, the other one will pick up a pipe and be ready for the next.”

An important element of the company’s robotic system is software that provides a man-machine interface (MMI). Comparing MMI to how a computer relates to the human senses – a monitor for the eyes, speakers for the ears – Mr Søndervik explained that through touch, sound and sight, even miles away, the system will be able to provide real-time feedback. If a problem arises and the machines need to stop, that decision would lie with the operator – the human. Communication through the MMI will also be straightforward, not via a combination of numbers and letters. “We don’t want fault codes coming up saying it’s an ABC25 fault code; you don’t know what that is,” Mr Søndervik stated. “We want software to directly show you what’s wrong. If anything goes wrong inside the machine, you want to be able to see that instantly.”

An ideal MMI would consist of a single piece of software. “We don’t want different software. We want one software that can visualize, control and also do the simulations,” he said. The goal of having different equipment within the robotic system work both as standalone machines and as one coherent unit also applies to the software. “This software needs to be able to control one machine, but we also need to control the group of machines,” Mr Søndervik noted. “We need software that gives us an excellent managing interface.”

In autonomous robotic drilling, the key is having autonomous machines. In Latin, autonomy means “one who gives oneself their own role,” Mr Søndervik said. Walking is an automatic role of humans. “You don’t think when you walk. Same with cycling – you’ve done it once, you never forget.” Different industries, such as the airline industry, already utilize autonomous systems. “A modern passenger airplane is a big flying robot, with many different systems controlled one by one and controlled as a unit,” he said. In the automobile industry, new cars from Google and Mercedes can drive by themselves, he added. The next step is for the oil and gas industry to create robotized drill floors with autonomous machines.

Robotic Drilling Systems is developing a system to be rolled out in Stavanger in 2014 that will completely robotize the drill floor. “The command being given, as in make a BHA or trip in pipe, and the system will then take over,” he explained. “There are no humans working on the drill floor, but still it does the same job.”

The obvious safety benefit is achieved by removing people from the drill floor. For the equipment, “they all know where they are at any given time. No machine can destroy or damage each other,” he stated. Cost savings will be realized per unit. “Electric robotic systems have lower cost per unit,” he said. “It equals easy installment – a plug into the volt, and they’re up and running.” In the long term, compared with hydraulic systems, the robotic system also will have a higher life expectancy, which can further be improved with software, he noted.

Cary Moomjian, CAM OilServ Advisors, expects drilling contracts to become even more complex due to implications from Macondo-related litigation.

By Katherine Scott, associate editor

The Macondo incident has significantly impacted contracting considerations in the drilling industry and will continue to add complexity to contracts, Cary Moomjian, president of CAM OilServ Advisors, said at the 2013 SPE/IADC Conference & Exhibition in Amsterdam on 7 March. Court rulings in Macondo-related litigation have and will continue to impact operators, drillers, and service and supply companies, particularly in respect to pollution liability in general and contractual indemnity/release provisions in particular, he explained.

A key question that has been debated for years, Mr Moomjian noted, is “whether contractual indemnity will be upheld in the event of gross negligence.” In the January 2012 rulings on summary judgment motions involving the drilling and cementing contracts related to Macondo, the court determined that contractual indemnification may apply even in the event of gross negligence or strict liability but will not be applicable to protect a party against intentional wrongdoing, he said.

“An indemnity involves one party’s agreement to protect, defend and indemnify another party from a third-party claim, such as a pollution liability claim,” he explained, distinguishing it from a release. “A release would be a typical provision where each party releases the other party for damage and loss. Unlike an indemnity, in the case of a release, if the release is valid, I have no recourse and it is not enforced in gross negligence.”

Rulings from January 2012 also found that the scope of indemnification excludes punitive damages. Further, contractual indemnification may apply to protect an indemnified party from penalties assessed under the Oil Pollution Act (OPA) of 1990, although not under the Clean Water Act (CWA), the court ruled.

“Under OPA 90, there is a provision in the act that expressly permits contractual indemnification. The second aspect is that OPA 90 penalties are considered to be compensatory rather than punitive in nature,” Mr Moomjian said. “Compare that to the Clean Water Act, which was adopted later. There’s no provision addressing indemnification one way or the other.” According to the US EPA, the OPA was signed into law largely in response to rising public concern following the ExxonValdez spill. The agency states on its website that the purpose of the OPA was to improve the US’ “ability to prevent and respond to oil spills by establishing provisions that expand the federal government’s ability, and provide the money and resources necessary, to respond to oil spills.” Conversely, the website said the CWA “establishes the basic structure for regulating discharges of pollutants into the waters of the United States and regulating quality standards for surface waters.”

After Macondo renewed the focus on contractual provisions addressing liability for pollution emanating from the well, many operators have been proposing to modify the traditional risk allocation by qualifying the general indemnity relating to subsea pollution to exclude coverage for punitive damages, fines or penalties attributed to the contractor. Mr Moomjian said post-Macondo contracting has also witnessed an increase in proposals by operators to negate indemnity provisions in the event of gross negligence or willful misconduct by the contractor.

From a drilling contractor perspective since Macondo, companies have also been proposing to change drilling contract terms. This includes expansion of the contractor group indemnified parties to include service companies, equipment manufacturers and other parties that have obtained an indemnity from the contractor; provisions stating that a material breach of contract shall not impact the contractual risk allocations; terms addressing recovery of costs incurred to enforce the contractual indemnities; and an obligation to fund defense of potentially indemnified claims.

Should a company decide not to address Macondo rulings in their contract, however, Mr Moomjian noted that his recommendation is “to write your contract as you would pre-Macondo, but state that those indemnities shall be applied to the fullest extent permitted by law.”

Although the initial impact of Macondo primarily has been reflected in contracts for drilling in the US Gulf of Mexico so far, Mr Moomjian said he believes that this “game-changer” event will ultimately impact contracts for US land and non-US operations as well.

To read more about contractual considerations in the post-Macondo world, please see SPE/IADC 163483, “Macondo Litigation and Its Impact on the Offshore Industry – What Every Operator, Driller, Service and Supply Company Needs to Know,” by Cary Moomjian Jr, CAM OilServ Advisors.

NOV’s BOP testing facility in Houston can run seven types of BOP tests, including high temperatures, low temperatures, fatigue and sealing characteristics. Most tests run at the lab exceed API standards.

By Katherine Scott, associate editor

As industry drills deeper wells in increasingly harsh environments, the upper limits of BOP equipment is constantly being pushed. Even under such conditions, a BOP and its sealing elements must perform flawlessly. Such high performance can be achieved only through aggressive development and testing, said Joe Liotta, National Oilwell Varco (NOV), at the 2013 SPE/IADC Drilling Conference & Exhibition this week in Amsterdam. Testing and qualification of BOP equipment as detailed by API Spec 16A requires facilities with the capability to test BOPs in multiple environments and operating scenarios. NOV’s R&D center, located in Houston, is equipped for testing fatigue, high temperatures up to 177°C (350°F), low temperatures down to -26°C (-15°F), stripping, hang off, sealing characteristics and shearing.

“We took a rather unique approach to the design of the facility,” he said, which has been operational since October 2011. “We looked at manufacturing principles, such as lean manufacturing and quick response manufacturing,” Mr Liotta said. Although such manufacturing methods are not usually applied to R&D testing facilities, “we felt that this would help to manage it such that we would maximize efficiency and minimize waste and lost time.”

The multimillion-dollar R&D lab, operated by NOV’s Pressure Control Group, is made up of two primary parts: eight large-bore test bays and five small-bore test bays. “You have dedicated people that work (in each cell) on specific equipment. It really helps to establish ownership in the products and the tests that are being performed,” Mr Liotta said in presenting SPE/IADC 163573 at the Drilling Conference. In most cases, NOV believes it’s important for the tests to exceed API’s minimum standard. “You’re not only testing the BOP but the supporting equipment at the same time.”

To determine whether a test is conducted, facility technicians go by three criteria: is the equipment prepared and available, the priority or importance of the test as determined by dedicated planners, and lab capacity, he said. In the past, it was common to run tests in a sequential process: prepare and complete one test and then look for what was next. “But with all this infrastructure (in the lab), we knew in order to keep it busy, we needed to set up a parallel process. So now we have dedicated teams that prepare all the kit required to perform a test and stage it all together while the tests are being performed. That way, as soon as a bay becomes available, the test is completed, and the next test can be started from there.”

High- and low-temperature tests are among five other types of BOP tests that can be run at the lab. Per API Spec 16A Section 5, there are six dedicated low-temperature ratings and six high-temperature ones, ranging between -26°C (-15°F) and 177°C (350°F). Testing and qualifications also must account for valves, hoses, fluids and any other components of the equipment that might be exposed to these extreme temperatures. A room built for the low-temperature tests is fully insulated, including the floor to prevent groundwater from freezing. The company also developed a system of cooling the BOP from the inside to decrease the time needed for each test.

Another test that gets a lot of attention is the fatigue test, Mr Liotta said. “It’s important because of reliability, and it’s also very hard on the infrastructure and on the processes because it takes so long to run. We found we could complete a full fatigue test in about 36 to 48 hours, and that’s great because then we can repeat the test, and we can try other variables or other test conditions, which results in a more robust product.” Among the challenges of conducting a fatigue test are having a system that has minimal technician involvement, logging sufficient data for the test and maintaining complete control over operator pressure from external source.

A sealing characteristics test, according to API 16A, “determines the actual opening or closing pressure required to either maintain or break a wellbore pressure seal. The test shall also define the ability of the ram packer to affect a seal when closing against elevated wellbore pressure.” Documentation includes a record of closing pressure versus wellbore pressure to affect a seal against elevated wellbore pressure, and a record of operator (closing or opening) pressure versus wellbore pressure to break a wellbore pressure seal. Mr Liotta said the biggest challenge in this test is the second part, ram closure against elevated wellbore pressure.

Because schedules can change several times a day in the R&D lab, NOV has developed a “dashboard” work order system so employees can see what’s going on in each test bay. The dashboard also serves as a portal for data collection, and historical data can be leveraged to generate performance metrics and downtime information. This data can expose areas of improvements and drive process improvement projects. Further, “each of the stations has a control panel located outside the bay, and they have full control and can see 360° cameras,” Mr Liotta said. “The goal is eventually to automate the testing with the controls that we have in place, so that we could maybe have one technician perform testing that’s automated in two bays.”

Click here to read more about the NOV R&D center.

Ole Slorer, managing director, global oilfield services for Morgan Stanley Research, moderated the plenary session, “Delivering Wells in a Critical World,” at the 2013 SPE/IADC Drilling Conference in Amsterdam on 6 March.

By Joanne Liou, associate editor

Driven by increasing worldwide demand, the challenges industry faces are becoming more pronounced. “We need to bring on about 27 million barrels per day of new production over the next seven years in order to meet 1% to 2% demand growth per year,” Ole Slorer, managing director, global oilfield services for Morgan Stanley Research, stated at the 2013 SPE/IADC Drilling Conference. Mr Slorer moderated the plenary session, “Delivering Wells in a Critical World,” in Amsterdam on 6 March. Two of the biggest growing segments that will help the industry meet the world’s energy demand are ultra-deepwater and liquids from shale plays, he said. However, the extraction of those resources presents increasing environmental risks and complexities in well design.

In a wide-ranging plenary session, Scott Sigurdson, vice president, area wells – deepwater at BP Global Wells Organization; Øyvind Tuntland, vice president of Petroleum Safety Authority (PSA); Lyndol Dew, senior vice president of worldwide operations at Diamond Offshore Drilling; Rosli Hamzah, head of well delivery at PETRONAS; and Steve Orr, drilling group president for Schlumberger; addressed how industry is approaching these challenges.

BP’s in-house advanced cementing course will reinforce requirements and proficiency in meeting cementing challenges, Scott Sigurdson, vice president, area wells – deepwater at BP Global Wells Organization, said.

Many steps are taken to ensure the long-term integrity of a well, from identifying methods to be used in well construction to involving regional engineering specialists. In part, BP has targeted the challenge through cementing, making cementing a formal sub-discipline and establishing a competency framework with structured development and career opportunities. “An in-house advanced cementing course is near completion to reinforce requirements and deepen proficiency across a broad range of cementing challenges,” Mr Sigurdson explained.

To further ensure performance, the company uses an independent safety and operational risk authority to verify that requirements are being met. “If a well does not initially conform to our internal standards, a formal risk assessment is done to determine the forward plan. We’re also systematically auditing our cementing suppliers globally, with a focus on competency and compliance with their internal design and approval processes.”

Another key focus is well control competency development in deepwater. At BP’s Global Wells Institute in Houston, a simulator was recently installed to complement a new applied well control training course. “The training is unique and trains key rig personnel, including BP drilling and rig services staff, in a team environment where we simulate potential well control challenges,” Mr Sigurdson said.

Beyond individual company initiatives, industry also must push for collaboration on critical issues. “It’s important we work with all our contractors to manage risk with a one-team approach. We need all people involved in support of the well to be focused and working together toward safe and reliable operations,” he continued. Several examples of industry collaboration targeting deepwater accident and prevention response capabilities have already been established, such as the Subsea Well Response Group and the US Center for Offshore Safety.

Another example of industry collaboration is the PSA, which continues to interact with groups, such as the International Regulators Forum and the North Sea Offshore Authorities Forum, to better navigate technical and operational risks and public expectations. Last year, the Norwegian regulator began to form multinational audits, which focus on sequences, action, discussion and organization, for different aspects of a drilling operation, such as well control procedures and communication between client, drilling contractor and service contractors.

In terms of barrier management, PSA’s well control incident studies found that there is more focus “on improving handling of a well control situation rather than on preventing a situation in the first place,” Mr Tuntland explained. “We think there should be stronger emphasis on technical lectures to improve safety.” He also reported that the OGP Wells Expert Committee continues to analyze BOP reliability, but there have been no formal results yet.

Lyndol Dew, senior vice president of worldwide operations at Diamond Offshore Drilling, said his company has established three fleet integrity assurance goals: keep the pointy end up, keep hydrocarbons where they belong and don’t give up ship.

There is also a growing interest in crew resource management (CRM), which focuses on development of non-technical skills, human factors, interpersonal communication, teamwork, situation awareness, stress management, leadership and decision making. CRM was originally developed for aviation, but “many players, such as OGP and regional gas associations, have put CRM on the agenda to assess possible application in the oil and gas industry,” Mr Tuntland said. “If we’re going to increase staff offshore, we need to look at our training, and we need to look at crew-based simulation training. We urge the drilling industry to simulate further to more crew-based simulation training.”

The public’s concerns about industry practices are well recognized, but “What does the public really want from drilling contractors?” was the question that Mr Dew posed. The answer is simple, he believes: invisibility. “They don’t want to hear from us; they don’t want us to cause problems. They just want us to do our job and deliver the fuel,” he said.

Mr Dew also discussed Diamond Offshore’s journey toward improved process safety. After a 2005 incident in Texas, it was reported that the companies involved concentrated too much on personnel safety and not enough on process safety. “I gathered my team shortly after reading that report and said, ‘Hey, could this be us? Are we so concerned about the bubble of loss of life and the actual level of slips, trips and falls and LTIR frequency rates that we’re missing the big picture?’” The company then went to work on defining process safety for drilling contractors, concluding that “our processes are the things that we do to prevent multiple fatalities,” he said.

The company ultimately established three fleet integrity assurance goals:

1. Keep the pointy end up, referring to the derrick.
2. Keep hydrocarbons where they belong.
3. Don’t give up the ship.

Looking forward, Diamond Offshore is working on defining each individual’s role – down to the roustabout and roughneck – in meeting the three goals, Mr Dew noted.

Rosli Hamzah, head of well delivery at PETRONAS, described the company’s well integrity assurance program, which begins with a technology peer review.

For PETRONAS, the company knows well that its own success or failure has significant influence on Malaysia. “We are owned by people of Malaysia, and 40% of Malaysian revenues come from PETRONAS. We carry a very heavy social responsibility,” Mr Hamzah said.

PETRONAS’ well integrity assurance program begins with a technology peer review. All designs go through peer review by experts and engineers on various well components, as well as through reviews by in-house independent review committees, Mr Hamzah said. “We consider a well kick equivalent to a lost-time incident,” Mr Hamzah noted. “We investigate all well kicks.”

Providing a service company perspective, Mr Orr described the gradual shift at Schlumberger to competence assurance. This takes personnel beyond simple training or certification. “We’re moving from certified training to high-risk operation competency assurance,” he said. “We’re now checking competencies.”

Corporate standards will help unite operations, training and verification of what’s done, Steve Orr, drilling group president for Schlumberger, said.

Such assurances of competence are especially important for ensuring well integrity, and the company has established corporate standards that cross multiple segments within Schlumberger. “Corporate standards bridge across operations, training and verification of what’s done,” Mr Orr explained. “We have who is responsible in terms of operations, in terms of manufacturing to ensure that we have accountability, but on top of that, we can manage the change and management aspect of it.”

The company also has embarked on an integrated drilling strategy to enhance the value that its discrete products and services can bring to operators. “It’s a systems approach that is going to make the next step-change,” Mr Orr stated. “It’s the alignment of all the stakeholders that will bring the next step-change in operational integrity.”

Watch an exclusive video interview with Steve Orr about Schlumberger’s integrated drilling strategy.

Kevin Neveu, president and CEO of Precision Drilling, has been named chairman of the 2014 IADC/SPE Drilling Conference, to be held 4-6 March in Fort Worth, Texas.

Kevin Neveu, president and CEO of Precision Drilling, has been named chairman of the 2014 IADC/SPE Drilling Conference, to be held 4-6 March in Fort Worth, Texas. The event provides the opportunity for producers, contractors and service company professionals to meet, discuss, evaluate and share ideas to advance worldwide drilling operations, promote solutions to common problems and improve overall efficiency and profitability. “It’s a privilege to serve as chairman of the industry’s premier drilling event. I look forward to working with my peers around the world to deliver an inspiring program for the 2014 conference,” he said.

Mr Neveu was appointed CEO and a director of Precision Drilling in August 2007 and became president and CEO in January 2009. Prior to joining Precision, he was previously president of the Rig Solutions Group of National Oilwell Varco (NOV) in Houston, where he was responsible for the company’s drilling equipment business. Over the previous 25 years, Mr Neveu held senior management positions in London, Moscow, Houston, Edmonton and Calgary with NOV and its predecessor companies.

Mr Neveu holds a Bachelor of Science degree and is a graduate of the Faculty of Engineering at the University of Alberta. He is a Professional Engineer as designated by the Association of Professional Engineers, Geologists and Geophysicists of Alberta. In 2002, Mr Neveu completed the Advanced Management Program at the Harvard Business School.

He was appointed to the IADC Board of Directors and as a member of the IADC Executive Committee in January 2010. He serves on the boards of RigNet and Bonanza Creek Energy,  has been a director of the Heart and Stroke Foundation of Alberta since 2009 and is a director for a not-for-profit national sports governing organization. In 2012 he became a member of the Canadian Council of Chief Executives and a member of the Advisory Council for the School of Public Policy at the University of Calgary.

Drilling Contractor associate editor Katherine Scott speaks with David Brunnert, vice president of Drilling Tools and Intervention Services for Weatherford, at the 2013 SPE/IADC Drilling Conference & Exhibition in Amsterdam on 6 March. Mr Brunnert explained the importance of early collaboration and how the approach can be applied in both business segments of Weatherford that he oversees. From well construction to intervention, Mr Brunnert believes that there are many opportunities for more collaboration among operators, drilling contractors and service companies.

Click here to watch another exclusive video and read more about industry’s need for more collaboration earlier in the well construction process to address complex challenges.

Michael Jellison, NOV Grant Prideco spoke at the 2013 SPE/IADC Drilling Conference & Exhibition in Amsterdam about common challenges in shale drilling, which is becoming more global. There are strong expectations for growing development of unconventional resources in regions like Europe, South America, Australia and various regions of Asia Pacific, he said.

By Katherine Scott, associate editor

When typical wells in the Bakken Shale are 17,000-ft MD, 11,000-ft TVD with a 6,000-ft horizontal reach, demands on drill pipe become significantly higher, Michael Jellison, NOV Grant Prideco, said at the 2013 SPE/IADC Drilling Conference & Exhibition on 5 March in Amsterdam. “It pushes the drilling equipment and rig crews beyond the requirements of typical onshore well construction projects.” Further, these wells can have high bottomhole formation temperatures that, in some cases, approach 375°F, which can precipitate major problems for the drill pipe and drill string, he explained.

With the dramatic increase in North American shale drilling over the past several years, as well as strong expectations for growing development of unconventional resources in regions like Europe, South America, Australia and various regions of Asia Pacific, Mr Jellison offered several solutions to mitigate common challenges in shale wells. “These wells are pretty challenging, and there’s a steep learning curve associated with them,” he said in presenting SPE/IADC 163447, discussing challenges related to hardband and drilling wear, downhole heating failure and stick-slip.

Proper hardband selection, application and maintenance are essential to successfully and safely drill challenging shale wells, especially as many of these wells encounter highly abrasive formations that can generate heavy wear on the tool joints, Mr Jellison said. The correct hardband solution can maximize drill string life by protecting the tool joints from excessive wear, minimize wear of the intermediate casing strings in the well and reduce the friction coefficient between the drill pipe and the wellbore.

For critical shale applications, he noted, the hardband system must be casing friendly, with no tungsten carbides in its formulation. They should be applied in a raised configuration to maximize tool joint protection, and both the pin and box members should include hardband to protect the tool joints. “On shale wells with abrasive formations, it is essential to implement a rigorous hardband inspection and reapplication program to ensure the tool joints are protected and the useful life of the drill string is not unnecessarily compromised.”

Downhole heating failure is another major concern. Although not unique to shale applications, the directional drilling followed by long horizontal sections common in shale drilling can promote high side loads between the drill pipe and wellbore; this can quickly create conditions conducive to downhole heating, Mr Jellison explained. He added that drill string failures caused by friction heating of bottomhole assembly (BHA) components and drill pipe have risen significantly over the past several years. The consequences of downhole heating can be severe, often resulting in axial separation of the drill string and creating potential well control issues, costly fishing jobs and other remedial efforts, he said. Using drilling fluids with low coefficients of friction, minimizing doglegs and dogleg severity, and utilizing friction-reducing tools, such as drill pipe rubbers and non-rotating drill pipe protectors in areas of the drill stem where high side loading exists, are several ways to prevent downhole heating failure.

Stick-slip problems have also been encountered in many shale wells, he said. The primary concern for the drill string is that severe stick-slip conditions can cause downhole connection back-offs. “These problems have not been isolated to certain shale plays or fields, and furthermore, the problems have not been consistently experienced within the same field, indicating that drill bit and BHA designs, along with drilling practices and procedures, have a strong impact on stick-slip and are critical to mitigating problems,” Mr Jellison said. Mitigation techniques include incorporating torque control components into the bit design, adding special rotary directional subs to the BHA, and using a drill bit and reamer in combination to reduce torque and promote torque stability.

Illustrating this particular challenge, Mr Jellison discussed a case study in the Haynesville in North Louisiana, where a string of 4 1/2-in. drill pipe was being used to drill a well that had a projected total MD of 16,700 ft. Rig reports indicated tight hole problems and frequent stuck pipe instances, Mr Jellison said. The drilling operation included extensive backreaming operations, and the top drive stalled several times, indicating severe downhole stick-slip. An investigation concluded that improper connection make-up on two of the three drill pipe back-offs very likely contributed to the back-offs, he said. “Stick-slip was clearly a major factor in all the connection back-offs.”

Concluding his presentation, Mr Jellison stressed that creative solutions will be required to continue to overcome industry’s shale development challenges. “We’ve made a lot of progress and had a lot of successes in shale drilling applications. There will be more challenges in the future, but I’m confident that our industry can overcome them.”