Zhang Mi, chairman and president of Honghua Group, spoke with Drilling Contractor at the 2013 OTC. He noted that while his company’s current focus is on the US onshore market, he believes Honghua can eventually deploy the same technologies in China once unconventionals development expands in that country.

Honghua Group and its US subsidiary Honghua America are developing a next-generation onshore rig for shale drilling called the US #1; a prototype is under construction at the company’s Houston factory and scheduled for completion in late 2013 or early 2014. Further, the company is working with Baker Hughes to field test Honghua’s 6,000-hp hydraulic fracturing pump in Texas. Speaking during an exclusive interview with Drilling Contractor at the 2013 OTC, Zhang Mi, chairman and president of Honghua Group, noted that such technologies are examples of his company’s focus on the US onshore market; yet, they are also technologies that he believes Honghua can eventually deploy in China once development of unconventionals expands in that country.

The US #1 rig has been designed to be highly mechanized and highly automated, Mr Zhang explained, and one technology that will be incorporated is Honghua’s new direct-drive triplex mud pump. The pump is driven by a top-mounted AC motor that powers the pinion shaft. This removes the intermediate transmission (e.g. belt, chain and gear), reducing maintenance and vibrations and lowering noise.  A smaller environmental footprint is another key feature of the US #1 rig. Mr Zhang noted that it has been designed to be powered with natural gas and LNG, and perhaps even grid power in some cases. “If (US #1 is) successful, it will be an example for Honghua’s next-generation rigs.”

The company also continues work on its 6,000-hp frac pump, introduced at last year’s OTC. Honghua is now working with Baker Hughes to bring this technology to the US market for field-testing, Mr Zhang said. “Once the field tests are complete, I believe it will also bring about step-changes for shale drilling in the US.” Field-testing will likely take place in Texas around August, he said.

Honghua Group’s triplex direct-drive pump, exhibited at the 2013 OTC, reduces maintenance, increases service life and reduces noise emissions and vibrations. The pump will be integrated into Honghua’s next-generation rig, the US #1.

Looking toward the Chinese market, Mr Zhang explained that although there are approximately 2,000 land drilling rigs operating in China, most of them are older mechanical or SCR-style rigs. “There is a significant need for renewal of the fleet,” he said, adding that he believes innovations such as Honghua’s direct-drive triplex pump will be able to impact the Chinese market once it’s proven in the US. “The locations in China where there’s potential for shale gas are not like Texas, where you have wide spaces where you can build wellsites. In China, they are located in mountainous regions, so access to shale gas reserves is more difficult. Being able to reduce the footprint is especially important.”

Although onshore rigs and technology remain at the core of Honghua’s business, the company is also pushing ahead with its entry into the offshore rig construction segment, with the large-capacity Honghai mobile crane the centerpiece technology driving their efforts. “When our Honghai crane is completed with a lifting capacity of 22,000 metric tons, you can construct the entire platform on land and then transport it offshore as a complete piece… We believe this will be a first in the world,” Mr Zhang said.

Construction of the crane began in October 2012 near Shanghai. Once completed, Honghua plans to use it for large-scale and simultaneous production of five to 10 offshore rigs, he said. The crane will be completed by the end of 2013 or Q1 2014, and Mr Zhang noted that discussions for offshore rig orders are ongoing, primarily with non-Chinese companies.

Dual-fuel kits on drilling rigs provide flexibility and carry a lower conversion cost than LNG-dedicated rigs, Bryant Dear, Noble Energy, said at 2013 IADC Drilling Onshore Conference in Houston on 16 May. However, the cost savings for dual-fuel engines are still to be determined, he added.

After a pilot program initiated in early 2011 to compare the use of LNG versus diesel to power drilling rigs, Noble Energy now has four dual-fuel rigs and one LNG-dedicated rig operating in the DJ Basin and the Marcellus. “It’s going to cost you to convert your rig to LNG. There’s a price tag to it, but we see that price tag being well worth it,” Sean Howley, senior business analyst for Noble Energy, said in a presentation at the 2013 IADC Drilling Onshore Conference in Houston on 16 May. “We actually think it will pay off in two years,” he said of the LNG-dedicated rigs. “After that, it’s all savings.”

During the pilot program, Noble Energy gathered 12 months of operating data on three rigs – two that were LNG-dedicated  and one running on diesel. The goal was to demonstrate the operational and economic viability of displacing diesel and powering the majority of Noble’s rigs with LNG, Bryant Dear, a co-presenter with Mr Howley, explained. Mr Dear is a drilling engineer in the DJ Basin for Noble Energy.

After evaluating the use of field gas and CNG, Noble decided that LNG would be the best option due to its higher energy density and consistent quality. There were also multiple options for turnkey providers, Mr Howley explained.

Sean Howley, Noble Energy, said at the conference on 16 May that his company is committed to using LNG for more operations going forward. Noble is currently building an LNG plant in Colorado to provide a closer fuel source.

Currently Noble has four fit-for-purpose dual-fuel rigs –Rigs 828 and 829 in the DJ Basin and Rigs 542 and 543 in the Marcellus, all from Precision Drilling. Although the cost savings that can be achieved for dual-fuel rigs are still “to be determined,” Mr Dear said, that is offset by a much lower conversion cost than LNG-dedicated rigs. Each of the four dual-fuel rigs is equipped with a GTI Altronics bi-fuel kit set up on three Caterpillar engines, he explained. “It’s too early to tell what our (fuel substitution) rates are, but we’re working to increase those as technology gets better and these systems get better… One thing we do know is you’ve got to displace as much diesel as possible (to achieve maximum cost savings).”

Mr Howley noted that Noble Energy’s commitment to LNG is such that the company is building an LNG plant in Weld County, Colo. “That’s going to bring our price much further down; it’s going to be an amazing option,” he continued. Not only does Noble plan to build a balanced portfolio of LNG-dedicated rigs and dual-fuel rigs, but the company is already expanding LNG applications to its frac fleet as well.

Noble currently has one frac engine running on a mix of LNG and diesel in the DJ Basin and plans to have another switch to dual fuels by June. “If we don’t need (the LNG) on a frac job, we can roll it over to one of our rigs. When we don’t need it on the rig, we can roll it over to a frac job. It provides some really nice synergies for us,” Mr Howley said.

Along with significant fuel cost savings by substituting diesel fuel with natural gas, operators can run the system with CNG, LNG, as well as field gas with a lower heating value between 850 and 1,250 Btu.

“It can detect the changes in the fuel quality and adjust itself without someone having to go fix settings or recalibrate anything,” Mr Roberts said. “Most importantly, we can do all this while maintaining the Tier 2 emissions that the engines have already been certified to.” A combined muffler and Cat Diesel Oxidation Catalyst included in the DGB kit help the engine sustain US EPA Tier 2 level emissions.

The DGB system is fully integrated with the engine control system, optimizing engine performance and ensuring that the engine always operates within safe parameters while blending diesel and natural gas.

Caterpillar introduced its Cat DGB system for land drilling and production last year at OTC. The latest system Cat 3512C (HD) engine will be commercially available in June 2013.

Cat is a registered term of Caterpillar.

The SeaONYX BOP surface control system utilizes a control platform that the company says has been designed for obsolescence management. The system addresses the challenge of ensuring availability, especially for electronic components, for a product expected to operate for 20 years or longer.

A BOP surface control system and operator interface designed for deepwater drilling was among several technologies GE launched this week at the 2013 OTC. The Acoustic Leak Detection System and the Subsea Multi-domain Condition Monitoring System were two other technologies introduced at the Houston event.

The SeaONYX BOP surface control system from GE Oil & Gas incorporates the company’s Mark Vle hardware and Proficy software tools. It uses dual redundant electronic control systems to control the subsea equipment. The Mark VIe control components allows the SeaONYX to use a configuration that has been installed in more than 2,000 thermal, wind, hydro and nuclear facilities, according to GE.

“SeaONYX is a control system that helps to manage our BOPs in deepwater drilling operations. The development of the new system is an outstanding example of importing industry-leading technologies from other GE businesses into the oil and gass space,” said Chuck Chauviere, president of drilling for GE Oil & Gas. “In this case, our customers will be benefitting from a control system solution that has a strong track record of success and high-level performance in the global power generation industry.

A critical advance with the new control system’s Mark Vle control platform is its inherent design for obsolescence management. The system addresses the industrywide challenge of ensuring availability, especially for electronic components, for a product expected to operate for 20 years or longer. The SeaONYX system does this by using a standard footprint for the major components that will be used in future releases of Mark VIe hardware.

Another feature of the Mark Vle architecture is the ability to “hot swap” certain components while the system is running. When an individual component requires replacement, the rest of the system remains active while it is replaced. The new component will boot up, configure itself and typically come back online in a matter of minutes, increasing system availability.

The two condition monitoring and sensing solutions for the subsea sector, launched by GE’s Measurement and Control business, will allow operators to monitor the integrity of their subsea installation. The Acoustic Leak Detection System (ALD) uses passive, acoustic hydrophone technology to detect and locate subsea oil and gas leaks by discriminating the noise of a leak from other sources of sound. Developed from naval military technology, the system detects “silent” leaks that occur when there is low flow rate or low differential pressure.

The ALD can detect both crude oil and gas with a coverage up to 500 meters.

The Subsea Multi-Domain Condition Monitoring System combines electric emission monitoring and acoustic hydrophones designed for monitoring the operating condition of subsea machinery and processes — from pumps and valves to supporting infrastructure. Typically combined with ALD to detect subsea leakage, the system performs multi-domain analysis supported by proven pattern recognition and machine learning algorithms to identify and display subsea structure, machine and pipeline activities and anomalies.

“As subsea exploration and production becomes increasingly important globally, many customers are looking to expand these topside capabilities to the seabed,” said Jens Abrahamsen, Naxys business leader for GE Measurement & Control, a GE Oil & Gas division. GE acquired Naxys in 2012. “By combining subsea sensors and acoustic condition monitoring with existing GE technology, GE customers can expand their view into operations and make intelligent, critical decisions about their operations.”

Lionel Lee, chairman and director of Triyards Holdings Ltd.

With the launch of TDU-400 jackup, a new Premium Class 400 HPHT rig, Triyards Holdings Ltd. has become one of three Singapore yards able to design and build its own proprietary jackups and self-elevating units. “The design is in the final submittal stage to ABS, and from a construction standpoint, we are getting ready to order components,” Richard Altman, senior vice president for global business development, said at a press conference Monday at the 2012 OTC. Triyards is in discussion with clients for a rig and hopes to have an order in the next three months, Lionel Lee, chairman and director, stated.

Richard Altman, senior vice president for global business development

The TDU-400 is designed to capitalize on the most advanced drilling systems and equipment available today. The design can be customized to meet the disparate needs of clients without having to be continuously redesigned, thus avoiding costs associated with variation in orders. “We wanted to design something that is shipyard friendly,” Mr Altman said. “We wanted to offer a premium performance package as light weight as we could develop with a jackup.”

The jackup can withstand 100-knot winds and meets wave criteria for global utilization. Providing accomodation for up to 220 personnel, the jackup boasts leg lengths of more than 535 ft (163 meters) and can operate in water depths of up to 400 ft (120 meters). The rig is rated to 32,500 ft drilling depth with 1.5 million tons of hookload. “We’ve incorporated a 1,000-ton topdrive, which gives you more torque,” Mr Altman said, “and today’s horizontal application or extended-reach applications need that additional torque.”

Mikael Troberg, Wartsila, discussed the emissions benefits of switching to natural gas from diesel, at the 2013 IADC Environmental Conference in New York City on 8 April.

Increasing emissions regulations and access to low-cost fuels are driving innovations in engine manufacturing. Requirements set by the US Environmental Protection Agency (EPA), as well as the designation of International Maritime Organization Emission Control Areas in the US and Europe, are raising the bar for lower emissions, stated Mikael Troberg, Wartsila, director of testing and performance, at the 2013 IADC Environmental Conference in New York City on 8 April. Due to variances among the fuels available in the market, it will take multiple technologies to help the industry reduce emissions across its global operations, he added.

Mr Troberg was joined on a panel at the conference by Aaron P. Trexler, power generation product line director, GE Oil & Gas; and Will Watson, offshore product marketing manager, Caterpillar Marine & Petroleum Power Division. Together, the experts shared insights into new engine technologies and advances in emissions control. Rhett Winter, IADC director onshore operations, moderated the session.

Panelists appeared to agree on the benefits of switching to natural gas from diesel. “We have 20% reduction in CO2, NOx is down 80% and SOx and particulates goes to 0%,” Mr Troberg stated. Further reduction in CO2 emissions is possible as engine efficiency improves, he added.

Rich-burn engine technology can provide diesel-like performance, higher fuel tolerance and reduced emissions, Aaron P. Trexler, GE Oil & Gas, said.

GE’s rich-burn Waukesha engine, for example, can run on any field gas, from propane to pipeline gas, according to Mr Trexler. This is important considering the varying gas quality across the US. “There’s a lot of varying gases throughout – from the Marcellus, Eagle Ford, Barnett and Bakken… A rich-burn engine allows you to run all those gases with very minimal treatment to the gas,” Mr Trexler explained. A rich-burn engine operates with a wide timing range to keep the engine running and prevent detonation, allowing for the higher tolerance and fuel composition. The engine also claims 95% lower emissions compared with diesel and 80% lower fuel cost.

As the price of diesel has continued to increase in the past few years, the delta is significant compared with LNG, CNG and field gas, Mr Trexler continued. Considering per-day fuel cost on a 1,500-hp rig site, it can cost upward of $4,500/day for diesel; that same amount of fuel to run the rig on LNG would be just over $2,500, or 41% less, he explained. “On CNG, it’s a little over $2,000, a 54% savings, and on field gas or associated petroleum gas, it’s a little less than $1,000.”

Caterpillar is focusing on engine performance to improve selective catalytic reduction (SCR) systems. “In this case, smaller is better, and we also need to maintain operating cost and performance,” Mr Watson stated. “The challenge we’ve had in our industry is trying to understand how to make this technology work with transient load applications.” Catalyst material has been refined to improve efficiency, not only in emission reduction but also in size reduction for the catalyst. “The engine itself remains unchanged; thus, existing proven engine parts can continue to be used, and for this particular solution, the SCR will meet Tier 4 interim and final regulations for EPA emission levels.”

Will Watson, Caterpillar Marine & Petroleum Power Division, explained how the company is improving engine performance to optimize SCR engine sizes to control operating costs.

Mr Watson reiterated the benefits of natural gas engines and further pointed to regulations around gas flaring, globally and in the US, which are “making people think, what are they going to do with that associated gas? It would be a crime to waste it,” he said. “Combined with the cost of diesel, you would get quick payback for a gas engine.”

Caterpillar is combining the power of diesel engines with the benefits of natural gas with dynamic gas-blending technology. The core of the technology is a compression engine that uses up to 70% natural gas. “It automatically adjusts the gas ratio to maintain performance of a diesel engine, maintains transient performance and also adjusts depending on the gas entering engine,” Mr Watson explained. “It monitors gas makeup to maintain that performance.”

Each technology has its own distinct advantages, but there is no silver bullet that meets the need for every application and every emissions regulation, Mr Watson said. “We are certainly doing our best to pair those solutions up and continue on with some of the cards we’re dealt with on the emission regulations side.”

The Schramm T500XD is specifically designed for horizontal and directional drilling to a total depth of 15,000 ft or more. It is currently headed to the Marcellus and Utica shale.

Schramm has launched its T500XD Telemast 500,000 lb hoist capacity drill rig currently headed to the Marcellus and Utica shales. The rig has a full 360° walking portability for fast moves from hole to hole without the traditional limits of two axis pad mounted designs.

The T500XD also offers a full communication interface connectivity to third-party data acquisition providers that utilize the internet or dedicated satellite communications systems to remote operation centers in multiple locations.

Specifically designed for horizontal and directional drilling to a total depth of 15,000 ft or more, the Schramm T500XD can control weight on bit without relying on drill collars and gross string weight alone.

It offers 35,000 ft-lbs of top head torque, third-party directional steering interface and 80,000 lbs of hydraulic pulldown capacity.

This rig includes an integral LoadSafe XD system that can handle 24 in.-diameter Range III tubulars weighing up to 10,000 lbs. Drill pipe is racked in the horizontal position for easy loading and offloading, thereby improving operator safety.

Telemast and LoadSafe are registered trademarks of Schramm.

Drilling Contractor associate editor Katherine Scott speaks with John de Wardt, president of De Wardt and Company, at the SPE/IADC Drilling Systems Automation symposium on 4 March, jointly held by the SPE Drilling Systems Automation Technical Section (DSATS) and the IADC Advanced Rig Technology (ART) Committee. The symposium preceded the 2013 SPE/IADC Drilling Conference & Exhibition in Amsterdam. Mr de Wardt was a primary organizer of the workshop. He also served as moderator of the sessions, which featured Andrew Stokes and Eric Nettleton from Rio Tinto, an integrated mining company. Mr Stokes and Mr Nettleton talked about the company’s Mine of the Future program, a project that is pushing Rio Tinto’s mining operations to new levels of automation and remote operations.

Werner Burger, Herrenknecht, spoke at the SPE/IADC Drilling Systems Automation symposium on 4 March about a large-diameter shaft boring system that is part of Rio Tinto’s Mine of the Future program.

Dr Roland Tucks, AkerWirth, explained the benefits of his company’s Mobile Tunnel Miner 6, a tunnel boring system for underground tunneling and mining, developed in conjunction with Rio Tinto, at the SPE/IADC Drilling Systems Automation symposium on 4 March.

Also speaking at the workshop were Dr Roland Tücks from AkerWirth and Werner Burger of Herrenknecht, who each discussed specific components used in the Mine of the Future program. Dr Tücks described AkerWirth’s Mobile Tunnel Miner 6, a mechanical excavation method that he said speeds up mining development, is safer than the conventional drill and blast method and has brought about a 60% decrease in drilling and bolting, which translates into cost savings. Mr Burger discussed Herrenknecht’s mechanized shaft boring system that helps vertically access deep ore bodies with a 180° rotating head. The detailed design is finished, he said, and the equipment is currently looking for a testing site.

Click here for more information on AkerWirth’s Mobile Tunnel Miner 6.

Click here for more information on Herrenknecht’s shaft boring system.

Mine of the Future is a trademark of Rio Tinto.

Fred Florence, NOV, outgoing chairman of the SPE Drilling Systems Automation Technical Section (DSATS) discussed the group’s current and upcoming plans, including work on an interoperability pilot project.

Michael Behounek, Apache, was elected the new chairman of DSATS at the SPE/IADC Drilling Systems Automation symposium in Amsterdam.

Thomas Geehan, MI-SWACO, provided an update on activities of the IADC ART Committee, including the Business Solutions for Drilling Automation Workshop that will be held at the IADC World Drilling Conference in Istanbul, Turkey, in June.

Andrew Stokes, global practice leader for surface mining innovation at Rio Tinto, explained how the company took a holistic view toward automation based on real-time data, at the Drilling Systems Automation Symposium on 4 March in Amsterdam.

The oil and gas industry is not alone in its journey to automate operations. Sharing similar benefits and challenges, Rio Tinto, an integrated global mining company, launched a project in 2007 that focuses on creating step-changes in the way the company mines for resources. Providing a high-level overview of the company’s Mine of the Future project, Andrew Stokes, global practice leader for surface mining innovation, and Eric Nettleton, manager of development, discussed what the company has learned and benefits already achieved through automation at the Drilling Systems Automation Symposium: Learning from Heavy Industry Front Runners on 4 March, just ahead of the 2013 SPE/IADC Drilling Conference in Amsterdam.

The supply picture for the mining industry has been challenging, Mr Stokes said, with easier mines already found and deeper ones found but not economically viable. To improve safety and to increase productivity and recovery rates – challenges similarly found in the oil and gas industry – requires innovation beyond continuous or incremental changes. “Seeing as technology is one of the few leads we have to really differentiate ourselves, there is a need to do this in the mining industry,” Mr Stokes noted.

Since the launch of the Mine of the Future program, the focus has been on three main components: surface mine automation, enhanced mineral recovery and rapid underground mine development. The vision for the program is to take “the best aspects of the past, which is the optimization, to come together to form an optimized large-scale mine,” Mr Stokes explained. “That’s the vision, and it’s largely driven not by removing people from operations but by automating the flow of information to people to make useful decisions in a timely manner, creating a holistic operational view.”

The collection of real-time data is key to creating the holistic view. “The challenge is developing that system for data integration,” Mr Stokes said. Given data from multiple sources during the operation, the trick is to tie all the information together, and rather than having a team of technicians try to infuse the data, he explained, have it done automatically.

“It’s not the individual components; it’s how it all comes together through systems integration, what we think will provide the real benefit to our operations.”

Eric Nettleton, manager of development at Rio Tinto, explained how the company created a blueprint of an automated mine in the Mine of the Future project to help drive the project toward step-changes in automation.

In developing the automated mine, a simple question that should be asked is, what should an automated mine look like? “It sounds obvious, but it’s a question that is rarely asked,” Mr Nettleton stated. Rio Tinto drew a blueprint of the end-to-end autonomous mine, identified all the components that would be needed and what information needs to be shared, allowing them to incrementally build the system. “The purpose of our system is to build an online, real-time model to provide the best picture of what’s happening so you can control your equipment and processes far better,” he said.

While Mr Nettleton believes they are still in the early days of the project, the company has already recorded benefits, seeing schedule variability drop from an average of 100 in 2008 to 53 in 2011. Train dump productivity also improved from an average of 100 in 2008 to 131 in 2011.

Although there is not a set metric to measure the benefits of automation, it is often compared relative to manual operations. “We are doing as well as manned operations, but more importantly what we’re trying to do with the auto-drill is make every drill as good as our best operator,” Mr Nettleton said. “If you get the best person out in the field, you’ll generally get a good result, but the purpose of automation is really to get that result consistently across the board.”

Mine of the Future is a trademark of Rio Tinto.

Fred Dupriest (left), who recently retired from ExxonMobil, received the 30th SPE Drilling Engineering Award from 2013 Drilling Conference chairman Øystein Arvid Håland (right) at the SPE/IADC Drilling Conference in Amsterdam on 5 March.

Specifically changing the way a job is done, rather than flawlessly executing the job the way it’s always been done, has led to many of ExxonMobil’s successes, Fred Dupriest said in accepting the 2013 SPE Drilling Engineering Award on 5 March at the SPE/IADC Drilling Conference & Exhibition in Amsterdam. “You’ve got to address a lot of things about yourself and how you work,” said Mr Dupriest, who recently retired after 24 years in field operations, followed by 12 years with ExxonMobil supporting drill teams in well planning and trouble response. He is the 30^th recipient of the drilling engin­eering award, which recognizes outstanding achievement and contributions to the advancement of petroleum engineering in the area of drilling engineering technology. “He is a shining example of how we continue to advance in our industry,” 2013 Drilling Conference chairman Øystein Arvid Håland, head of drilling & well for Statoil and a senior representative for SPE, said as he presented Mr Dupriest with the award.

Mr Dupriest expressed his pride in the industry, noting that ExxonMobil in particular has doubled its average footage per day in the last eight years. “At the same time, our well complexity has gone through the roof,” he explained. “We drilled 24 of the 30 longest wells in the world, and those 24 wells had less than 10% trouble costs on average.” The successes have been an accumulation of many factors, and “it’s been a workflow that we call limiter redesign. It’s a simple idea,” he noted. A limiting factor is identified and worked on until another factor becomes the limiter and needs to be worked on. “You keep doing that until you reach the economic limit of redesign.”

He shared four principles that have helped ExxonMobil become a leading performer:

1. Death to optimization. Industry must place more focus on engineering than on optimization, Mr Dupriest advocated. The industry is too used to defining what the boundaries are and snuggling up to them, he continued. In borehole stability, for example, when mud weight is raised, differential sticking and formation damage become a concern that is often pushed until “you start feeling a little bit more pain and start backing up. Then, there we are, and there we stay when we optimize,” he noted.

Fred Dupriest discussed four principles to create change – focus on engineering rather than optimization; making decisions deterministically, trust people; and get out of the way – in accepting his award during the opening session of the Drilling Conference.

By looking at the physics of formation damage, deterministically and not empirically, ExxonMobil found that things did not work the way they thought, based on empirical data. “Even though we raised mud weight, we simultaneously reduced formation damage dramatically by looking at physics,” Mr Dupriest stated. “Don’t optimize before you’ve reengineered your limiters. Engineer first, and optimize second.”

2. Death to empiricism; make decisions deterministically. Creating change goes beyond studying the status quo or data of how work is done and how people behave. In Mr Dupriest’s career, he has experienced an average of 15% to 20% trouble times in complex wells; however, since redesigning limits, the average has dropped by approximately 5%. Finding the balance between establishing standards and cultivating change is a challenge. “Empiricism is a problem. In some sense, we need standardized equipment; we need standardized practices. We need operational manuals, well control manuals,” he said, but “we need to understand that same culture that makes us really good is also the same culture that makes us resistant to change.

3. Trust in people. The answer to figuring out the physics of an operation might be found in a published paper or study, but the next step is to put it into practice with people – in particular, the people who actually drill the well, i.e., the driller or directional driller. Referring to what he called the “50/20/30 Rule,” Mr Dupriest explained that studies show approximately 50% of your employees will always do the right thing even at a cost or difficulty, and 20% more, in the right environment and under management that is facilitating and supporting the decision, will follow. Approximately 30% of people will not go along, simply because it is not in their nature. However, this lagging group will follow once the majority establishes what is right. “When you look at creating change, it’s that 50% you need to trust and believe in. Teach them how things really work. Study how things work and commit to those practices.”

4. Get out of the way. To enable change to happen, it is important for company leadership to present a path free of roadblocks. “Look at your company and see what it is about how you work and what gets in people’s way,” Mr Dupriest said. The challenges vary among companies and different business models, but it’s part of leadership’s role to strategically change the workflow to create change. “You really have to mechanically change pieces of your workflow so that people are always encouraged, supported or mechanically driven to identify limits and what they’re going to do to change it.”