Since the industry cracked the shale oil code in the Bakken in 1999, production in the play has increased 55% per year, a phenomenal growth rate for a new resource, Dr Boak noted. Meanwhile, there is a debate among some geologists over what to call the oil produced from shale. Aside from increased production in the Eagle Ford and Niobrara plays, operators such as Chesapeake Energy are ramping up activity in the newer hot plays, including the Utica, underlying much of eastern Ohio, and the Mississippi Lime, or Mississippi Chat, spanning across northern Oklahoma and southern Kansas. Despite concerns about hydrogen sulfide (sour gas) and high levels of produced water, particularly in the Tuscaloosa, there are no signs of a slowdown, he said. Nomac Drilling, an affiliate of Chesapeake Energy, has 113 marketable rigs with 110 active in the Eagle Ford, the Mid-Continent (including the Granite Wash, Cleveland, Tonkawa and Mississippi Lime), the Barnett, the Haynesville, the Bakken, the Marcellus and the Utica. Mr Minmier reports that rig rates have remained favorably steady since Q3 2011 and currently range from $18,500 in the Barnett to $29,750 in the Bakken.
All of Nomac’s marketable rigs are either working or undergoing upgrades for upcoming jobs.
Nomac is implementing an accelerated development program for drillers, directional drillers and rig managers aimed at reducing the time required to train competent rig leaders by 60% over traditional methods, Mr Minmier noted. Big E Drilling has shifted its fleet from the Haynesville to the Eagle Ford play, a move president and CEO Lyle Eastham said was justified given the current pricing environment. Today, the company’s five rigs are all operating in the Eagle Ford, including one the company built 18 months ago.
A Precision Drilling Super-Triple (ST) 1200 rig moves to the next well on a pad in the Marcellus play. Newbuild activity is also healthy in North America, with many of the major companies ramping up their fleets with efficient, highly mobile rigs suited for shale wells and pad drilling. Precision’s newbuilds for the US market include seven 1,200-hp rigs and 17 1,500-hp models.
Nabors Drilling USA Rig 681 (above) and Rig B4 (left) are both working in the Bakken Shale of North Dakota.
As the largest drilling contractor in Canada, Precision has operations in every major basin, notably the Cardium, Viking, Duvernay, Canadian Bakken, oil sands and heavy oil. From a technology standpoint, Mr Evasiuk believes the push for longer laterals will be achieved by further development of completion designs.
Outside North America, Precision has two rigs operating in Villahermosa, Mexico, and three in Saudi Arabia. Nabors Drilling has seen an uptick in US land rig utilization, primarily in the 1,000- to 1,500-hp size being deployed in most of the shale plays, said Denny Smith, director of corporate development.
Commodity pricing is the key driver for the shifting market, a trend that began back in 2010.
Nabors Drilling’s Rig 109 is working for XTO Energy in the Bakken Shale, where Nabors remains the largest drilling contractor.
Mr Smith said shale production, particularly horizontal drilling, has benefitted from an increase in pad drilling and major advances in downhole logging and real-time technologies. Through its wholly owned subsidiary, Canrig Drilling Technology, Nabors manufactures top drives and other rig systems and intelligent software technologies. Dayrates in Western Australia are at least 48% higher than US rates, despite gas prices that are $8-$10 (and rising) per gigajoule, considerably higher than North American prices, with acre lease costs of $500 or less, said Dennis Donald, a partner at Warrego Energy.
The company holds an unconditional permit to develop an 86-sq-mile block in the North Perth Basin, which is estimated to hold the fifth-largest reserve of shale gas in the world. Mr Donald cites lack of service infrastructure as the primary reason for the low unconventional production in the vast region, in part a function of the cannibalization of rigs being used for the vigorous coal seam gas activity in the eastern sector the country, thousands of miles away.
When Chesapeake Energy had the opportunity to be one of the first operators to test an automatic drilling system on a rig in Ohio’s promising Utica play earlier this year, the company took a forward-thinking view of what it might mean to be at the vanguard of what could be the future of drilling. This Utica well was a testing ground for the NOVOS operating control software platform from National Oilwell Varco (NOV).
NOVOS and its sister system, NEMSIS (NOV Enhanced Measurement System IntelliServ), which uses wired drill pipe to connect to downhole tools, are key features of the NOVA open-platform automated drilling system. However, moving into this new era not only requires innovations to develop technologies, it also requires companies to recognize the value of these technologies so they can be applied in a meaningful way to achieve step-changes.
A detailed process to develop the automation roadmap will ensure goals are properly identified and a common vision is established. The IADC Advanced Rig Technology (ART) Committee and the SPE Drilling Systems Automation Technical Section (DSATS) are collaborating to develop a drilling systems automation (DSA) roadmap outlining the steps anticipated in the development of drilling automation. The roadmap will incorporate best practices from oil and gas and other industries, including aerospace, the military and academia, to address topics such as advanced controls and robotics, unmanned ground systems, cybersecurity and smart grids. The IADC ART Committee, which has been collaborating with DSATS for years to advance drilling automation, is supporting the DSA effort. John de Wardt, president of De Wardt and Co and one of three industry experts spearheading the effort, believes that DSA embraces many facets of the drilling and completion process requiring collaboration to achieve success “Furthermore, the adoption of DSA will have a profound effect on the roles and responsibilities of workers, organizational structures and business models. Other industry leaders coordinating the effort are Dan De Clute-Melancon, technical adviser for Halliburton, and Ed Tovar, president of InTechSys, a technology consulting firm.
The committee’s goals are to develop a comprehensive graphic showing anticipated development in steps over a multi-year period in distinct streams, such as technical and non-technical, along with a report describing the details and reasoning behind the steps in the graphic. The roadmap will elaborate on the current status of each stream and work in progress and identify gaps and needs for research and development.
Independence Contract Drilling’s ShaleDriller Rig 202 features a climate-controlled driller’s cabin and advanced mechanization features, such as AC top drives, iron roughnecks and hydraulic catwalks.
Where Mr Willis does sees value for automation is in remote control technology and advanced mechanization and instrumentation. Independence Contract Drilling’s ShaleDriller 101 rig is working in Andrews County, Texas, for Apache Corp. Mr Willis listed the AC drive, which delivers fuel efficiency, as a distinguishing element of an advanced-technology rig. Using an automated drilling control system, Nomac Drilling’s Rig 77 drilled a test well in the Utica play for Chesapeake Energy. When it comes to full rig automation, or autonomy, there is a wide spectrum of viewpoints among industry experts. Slowly, industry is starting to look at automation as something more than just an interesting subject or an expensive way to get to deepwater and extreme drilling environments, he suggests.
For the NOVA system, “the financial discipline of land is fantastic for development, and we’re seeing enough value right now to do more testing,” Mr Reid said.
The industry has done a great job with mechanization, supported by innovations such as NOV’s TDS-1000 top drive.
NOV’s AMPHION Integrated Drilling Control System operated in the background in the event something went wrong. Further, NOVOS doesn’t need to take breaks and performs consistently compared with drillers’ variable skills and attention spans.
Going forward, Nomac and Chesapeake are hoping to take NOVOS to the next level and drill the lateral and possibly the curve as early as Q4 this year. Citing culture and a hesitance to invest significant capital upfront to upgrade older, mechanical rigs to accommodate automation as a significant barriers to change, Mr Ford believes there will be challenges to get the industry to adopt technologies like NOVOS and move toward widespread utilization.
More than half of Oxy’s rig fleet features highly mechanized rig floors, such as this one in the Permian Basin. Citing aging equipment and a lack of capital, along with culture, as significant barriers to change, Chesapeake’s Rob Ford believes there will be challenges to get the industry to adopt such a new technology and move toward widespread utilization. While drilling automation is getting a lot of attention these days, other technological advances have played significant roles in moving the industry forward and cannot be overlooked, said Tom Bates, chairman of Hercules Offshore. A similar incremental transformation has occurred with pad drilling and creating a factory-like environment in land operations.
Ed Jacob, chief operating officer for ICD, noted improvements in bit and motor technology are allowing operators to drill laterals of 10,000- to 12,000-ft or even longer. Seadrill’s new sixth-generation drillship, the West Auriga, has forward and aft top drives, pipe rackers and a driller’s cabin. While the US land market may be the testing ground for a lot of drilling automation, the more expensive offshore sector, with permanent platform installations, will be where automation technology gains a foothold first, Mr Bates believes. From a drilling contractor’s perspective, said Dustin Torkay, technical superintendent for Seadrill Americas, most new technologies have been transferred from adjacent industries.
That thinking has put offshore operators in the driver’s seat to sponsor and accept the risk for new technologies they believe will add value.
He believes cultural stubbornness and the “dated” dayrate business model are keeping the drilling industry from moving forward at a faster pace to deploy advances such as automated kick detection and accepting wireless technologies for offshore use.
Mechanization and pad drilling have helped to streamline operations in unconventional land plays. Some examples of offshore drilling technology are equipped on Seadrill’s new-generation rigs that feature a sophisticated zone management system called PIMS (pipe interface management system). Click here to read an article about Omron’s new integrated control and monitoring system that helps drillers manage all aspects of the drilling process.
The drill site has physically evolved with the advent of horizontal drilling and multiwell pads. BHP Billiton entered the US land market in 2011 and has since been drilling development wells in the Eagle Ford (pictured) and Haynesville and appraisal wells in the Permian.
North American onshore rigs are predominately occupied by horizontal, development drilling programs. Entering US land operations in 2011, BHP Billiton has since been drilling development wells in the Eagle Ford and Haynesville and appraisal wells in the Permian. Derek Cardno, VP of Drilling and Completions for BHP Billiton, visits a drilling site in the Eagle Ford, where the operator is drilling development wells.


Besides rig mobility, “the two most important components for efficient pad development and drilling of long laterals are the mud pumps and the torque of the top drive,” Jay Minmier, 2014 IADC Chairman and President of Nomac Drilling, said. In this overview of horizontal-drilling rigs, industry leaders from BHP, H&P, Nabors Drilling, Nomac, Patterson-UTI and Sidewinder Drilling share their insights on rig components and capabilities necessary to meet the demands of onshore horizontal drilling. No stranger to horizontal drilling, Nabors has been drilling horizontal wells in Prudhoe Bay since 1983 and participated in the Austin Chalk trend of the mid-’90s.
In North America, roughly 90% of Nabors’ rigs are drilling horizontally, and the industry is supporting the trend. The benefit of horizontal drilling is far reaching and not confined to unconventionals or shales.
Nomac’s customer base – Chesapeake Energy, EOG Resources, Continental Resources and Noble Energy, for example – is primarily in development drilling mode. The acceleration of horizontal drilling has led to numerous changes in rig capabilities, such as increased pipe racking capacity and higher hydraulic horsepower, which in turn requires additional power.
Horizontal drilling has led to significant changes in rig capabilities, such as increased pipe racking capacity and higher hydraulic horsepower, which requires additional power. With the greater well complexity and longer horizontal laterals, more mud pump pressure is needed to efficiently drill the wells.
For H&P, Mr Millwee estimates that about 75% of the newbuilds entering the land market are equipped with 5,000-psi systems.
Sidewinder Drilling, which has 42 land rigs in the US, is constructing two newbuilds – one to be delivered in January and the second in March 2015. Nabors Drilling has also observed more requests for 7,500-psi pumps, which are being retrofitted onto older rigs. Through 2015, Nabors will add 60 rigs to its fleet, all of which will have the option for 7,500-psi pumps.
The Nabors M-44 Rig (left) and Nabors Pace-X Rig 05 operate in Yoakum, Texas, in the Eagle Ford play. The wells that Sidewinder is drilling in Appalachia, particularly in the Utica, have a longer horizontal section than what they’re drilling in the Marcellus, where they generally run 7,000 to 12,000 ft.
In the Haynesville, BHP drills intermediate sections with hard, 40,000-psi compressive strength rock.
Operator demands for higher-torque top drives are leading to a shift away from hydraulic top drives in favor of AC-electric units. For land rigs, there are two facets to mobility: the ability to move from location to location and the ability to move from well to well on the same location. Rig 248 features a walking system capable of moving the mast and substructure with 20,500 ft of drill pipe and eight stands of collars.
The significance in pad drilling systems is prominent in terms of reducing nonproductive time. Sidewinder is constructing two newbuilds – one to be delivered in January and a second in March 2015.
The new generation of mast and substructures allows drilling contractors to rearrange its rigs to reduce the number the loads and connections, making the rigs move a lot more efficiently between locations. In the short term, and perhaps long term as well, Mr Millwee of H&P believes operators will maintain laterals in the 10,000- to 15,000-ft range to maintain the economics of the operation. While today’s horizontal drilling rig is capable of meeting operator demands, Mr Cardno of BHP believes there are opportunities to further optimize the drilling rig and operation.
Drilling & Rig operational efficiencies will certainly continue to evolve, both onshore and offshore, in a number of areas. Introduction “preparing for the future while reflecting on the past” iadc’s drilling onshore conference & exhibition is the only event specifically targeting. It’s not only toxic – it’s driven by a right-wing billionaire who profits more from flipping land than drilling for gas.
US land rigs that just two years ago were at work in prolific shale gas plays are on the move, delivering an oil and liquids boom that has yet to be fully quantified. As the Bakken play developed, the industry called it shale oil, a term used since the early 1900s to refer to organic-rich shale that requires heating to produce oil. The Tuscaloosa Marine play, a deep (10,000 to 15,000 ft) formation in central Louisiana and southwest Mississippi is believed to hold seven billion bbls of recoverable oil, an estimate made as far back as 1997, Dr Boak noted. In the Utica, Chesapeake plans to increase the rig count to 20 by year-end and to 30 by year-end 2014. The fleet is designed for horizontal and directional drilling at depths from 15,000 to 25,000 ft, with dayrates in the mid-$20,000s. Calgary-based Precision Drilling delivered 18 new rigs in 2011 and has contracts on 33 more to be delivered by the end of 2012 in North America.
They are designed with a small footprint in mind,” said Doug Evasiuk, senior vice president of sales and marketing, North America for Precision. Precision began shifting from the dry gas plays to the liquids last year, a trend that will continue, Mr Evasiuk said. Of the company’s 150 US rigs, 104 are operating in all the major plays, including the Bakken, Eagle Ford, West Texas, Mississippi Lime and Tuscaloosa. Utilization in February was around 85% but has recently declined due to the spring “break-up,” which occurs late in Q1 and can carry into Q2. By the end of 2012, the company will have 76 rigs, including several newbuilds, in the play. At year-end 2011, the company had 119 AC rigs in the US, with 31 newbuilds planned this year. Despite favorable market conditions, a lack of service infrastructure is retarding progress. The block contains the West Erregulla tight-gas field, which underlies the Kockatea shale play recently mapped by the US Energy Information Administration. A key example, he continued, involves the connection process, which varies considerably based on the skill, speed and decision-making behavior of the driller and crew. Under the watchful eyes of two drillers, Chesapeake’s well plan, including all anticipated surface drilling parameters, was programmed into the NOVOS control system.
It sits at the cutting edge of a new era that many believe is inevitable for an industry confronting the Big Crew Change while looking to optimize performance and reduce costs.
While debate continues over how new technologies should be adopted and how quickly the adoption process should go, experts agree that technology for the sake of technology is not the answer. The work is intended to reach a large audience using internet tools and will be available to all sectors of the oil and gas industry, as well as companies outside oil and gas production and consulting organizations. The graphic will address issues such as automation interoperability standards and protocols, real-world and cybersecurity, human interaction and fail-safe controls, simulation and testing, personnel training, legal liability, global regulatory issues, sustainability and job creation, intellectual property, and the business aspect of an automated upstream oil and gas industry.
Where possible, specific examples will be referenced and analogies used with other similar technology roadmaps. Oxy uses existing automation, such as through managed pressure drilling, as well as automation built into the basic control systems of advanced rigs. Other elements are having a highly modular, fast-moving design that reduces move time and an electronic control system that replaces air controls and the brake handle with buttons and joysticks. Advanced rigs make up more than half the fleet, and most are equipped with features such as top drives, big pumps, pipe-handling systems and hydraulic catwalks.
The rig used NOV’s NOVOS operating control software platform to drill a 7,000-ft vertical well section in less than three days. David Reid, NOV chief sales officer and senior VP for global accounts, believes the industry is about halfway down its path to full drilling autonomy.
NEMSIS measures parameters downhole, sends the data back to the surface quickly through wired drill pipe, then makes changes at the surface machinery to affect changes at the bit, Mr Reid said.
Except for a few occasions when the drillers had to take over the controls in the intermediate section, the operation went off smoothly, with no downtime. The company believes that on-the-rig intelligent monitoring is a future area of interest to identify, warn against and even prevent rig operations that might hurt people. Mr Bates is a firm believer that technology must make financial sense for both the user and the provider. The company is currently looking at ROP optimization using an electronic control system to adjust weight on bit and rotary speed to continuously optimize drilling parameters. The term is also sometimes used to describe mechanization, which also has delivered value to the oilfield. Mr Bates, who is also chairman of the board of Independence Contract Drilling (ICD), cited the case of Continental Resources, an operator that was able to reduce its cycle times by 35% and lower direct costs by 26% after switching from conventional to pad drilling in the Bakken. The rig, which is being deployed in the Gulf of Mexico, has been equipped with a simulator that provides a virtual representation of the drill floor equipment to facilitate onboard training. After switching from conventional to pad drilling in the Bakken, Continental Resources reduced cycle times by 35% and lowered direct costs by 26%, with the added benefit of production coming on stream faster. As industry continues to push into the ultra-deepwater and harsh environments, the emphasis is on size – 1,500-ton rigs, 20,000-psi BOPs and piping systems, he said.  “However, rigs don’t just perform drilling operations.
It manages the way various pieces of equipment interact with one another.  For one client, Seadrill has installed simulators on two drillships going to the Gulf of Mexico that provide a full virtual representation of the drill floor equipment to facilitate onboard training.
The comment by Mr Torkay regarding the negative effects of outdated commercial models is particularly relevant. No longer is a rig confined to drilling a single well before having to rig down, move to another location and rig up again. For Patterson-UTI Drilling, more than 80% of its 200-plus active rigs across the US are drilling horizontal wells. In the UAE, “the rigs we are running are all doing extended-reach horizontals – 10,000-ft measured depth on the horizontals,” said David Millwee, Regional VP – US Land Operations.


Nabors has about 300 active land rigs across North America, South America, the Asia Pacific and Middle East, the preponderance of which are drilling horizontal wells. The AC-powered FlexRig5 targets extended-reach horizontal wells for multiwell pad development.
In the US, industry has historically classified rigs by the horsepower of the drawworks, which made sense for drilling vertical wells. In North America, about 20% of Nabors’ fleet of 300 rigs is outfitted with 7,500-psi pumps. However, while the top drive plays a critical role in horizontal drilling performance, it also is a key point for failure. The older mechanical rigs will undergo selective upgrades to improve horizontal drilling performance depending on the field. Eventually, the fleet will be all AC top drives, all 1,600-hp mud pumps, all skidding and walking.
The latter has taken on greater significance due to pad drilling, although the former remains key to the efficiency of the overall drilling operation.
Over the next 18 months, that percentage will increase to 80-90% through newbuilds and upgrades. In West Texas, where H&P currently has approximately 90 rigs operating, some operators are still in delineation mode, Mr Millwee explained.
Both will be equipped with 7,500-psi mud pumps with permanent magnet motors that are smaller and lighter than conventional AC motors.
Whatever trends are occurring globally, US shales are the big story for 2012, driven by new play discoveries, technology advances and favorable pricing. Twelve new rigs are slated for delivery through April 2013, with two 1,500-hp rigs for oil drilling in the Powder River, Wyo., region and 10 1,200-hp rigs for the Utica. For Canada, where wells are generally shallower, the bulk of the rigs are the Precision Super Single design. The company’s large presence in the Haynesville has shrunk from the peak level of 26 rigs to just three.
Along with a significant presence in the Eagle Ford and the Permian Basin, the company has several rigs in the Mississippi Lime, with plans to move two more from the Haynesville. Most of the contracts are for the US market, but at least two have been designated for Canada and three for other markets.
The company holds a permit for a block in the North Perth Basin, estimated to hold one of the world’s largest shale gas reserves. Nabors also has 15 rigs in the Llanos Basin of Colombia and is drilling oil for two major operators in Russia. Most have features such as top drives and large pumps, but Oxy still uses smaller, mechanical rigs to drill simple vertical wells because they make more economic sense in those applications. With the operator’s affiliate Nomac Drilling, Chesapeake used NOVOS to drill a 7,000-ft vertical well section, representing what Nomac president Jay Minmier calls true automation. New technologies must deliver value in the form of safety, efficiency and economics to make sense in the oilfield. Through the collaborative effort of DSATS and the IADC ART Committee, the industry is able to stay abreast on changing technologies. Oxy has also been involved in field trials for ROP optimization systems and believes on-the-rig intelligent monitoring is a future area of interest to identify, warn against and even prevent rig operations that could hurt people or damage equipment or wellbore. However, the company also keep a few small, older mechanical rigs on contract to drill shallow, simple vertical wells. There comes a point where, when we start looking at ultra-high speed data capacities on both the surface and downhole measurements, combined with high-speed communication capabilities, we starting to see a potential for significant financial benefits,” he said.
Mr Minmier attributes the improved ROP to several factors, including the ability of NOVOS to make adjustments on a microsecond basis versus a driller making adjustments at a slower pace.
All five of ICD’s ShaleDriller walking rigs are working in the Eagle Ford, and Permian basins.
To get the very best performance from any company (ie skilled people), technology or entity requires contractual terms that ensure improved performance delivers higher reward. While this evolution is most prominent in North America, other land markets around the world, including Saudi Arabia and Argentina, are following suit. Mike Garvin, Senior VP, Operations Support for the company, said he sees that percentage and total number increasing in the coming year, as E&P companies transition to greater levels of horizontal drilling activity in markets that historically were predominantly drilled with vertical wells, such as the Permian basin. The impetus was to mitigate coning in the reservoir, thereby reducing water and gas intrusion while also increasing well productivity. The rig is suited to drill wells from 12,000 to 25,000 ft and features a bi-directional skidding system.
Hoisting capacity used to be a primary consideration, but with horizontal drilling, it has become less important. In the Eagle Ford area, “we have seen an increase from predominantly 8,000-ft laterals to 12,000-ft laterals, and then in West Texas we’re seeing the shift from vertical to lateral work with 6,000- to 10,000-ft laterals,” David Millwee, Regional VP – US Land Operations, said. Hydraulic horsepower translates to bigger pumps, higher volumes and higher pressures necessary to drive the higher torque and RPM capabilities of today’s downhole motors.
With the new generation of mast and substructures, drilling contractors can reduce the number of loads and connections to make rig moves more efficient between pads and with smaller-sized loads. Similar to the mud pump trend, Mr Minmier foresees a continued shift in Nomac’s fleet to reach 90% by the end of next year, as all of Nomac’s 16 newbuilds will include AC top drives and others will be upgraded. As the operators continue to better define their fields, we’ll upgrade the rigs for the efficiencies to do the pads.” The space between each well predominantly ranges from 25 to 50 ft, he noted.
Being able to move a rig quickly is a huge efficiency, where it traditionally takes three or four days to move a rig from pad to pad, we can literally walk to the next well on a pad in 45 minutes,” Mr Garvin of Patterson-UTI said.
Approximately 75% of Nabors’ US fleet – including approximately 150 AC rigs – have walking systems; outside the US, about 33% of its rigs are equipped. From the operator’s perspective, they must consider if the extra 5,000 ft up to the 15,000-ft lateral is providing more value.
Alluding to Formula 1 race cars, he described how crews have “gone from changing tires from 15 seconds to doing it in 2 or 3 seconds.
Technology advancements have certainly made the process more efficient, but there is still a lot of room for improvement. Drilling contractors are seeing steady and rising dayrates and high utilization as operators shift their focus from the dry gas basins and set their sights on liquids-rich regions, such as the Bakken, Eagle Ford and the Niobrara, along with emerging plays believed to hold huge reserves.
Dual-fuel systems are being added to the majority of its fleet to allow the rigs to run on compressed natural gas or liquefied natural gas, as well as diesel. The Super Single rigs also run range three tubulars and have fully automated pipe-handling systems. The company also plans to move one or two additional 1,500- to 2,000-hp rigs into the deep Tuscaloosa play to go after gas liquids and oil, Mr Smith said. Outside the US, the market is recovering, with Nabors’ land rig count expected to increase from 116 at year-end 2011 to 130 by the end of 2012. Giving members a voice during the development of automated equipment, processes and procedures is our main focus,” said Scott Maddox, director of IADC’s Drilling & Well Services Division.
These include instrumentation systems, top drives, bigger pumps, the pipe makeup system, powered catwalks, a rig-walking system and a BOP handling system.
A recent example is a record well drilled with one of our rigs, which achieved over 50,000 ft of reservoir contact. Where the majority of the wells they drilled were relatively straight just a year or two ago, now the majority is flipped to where they are going to be horizontal.
The economics at the time were a 30% increase in well cost yielded a doubling of production.
While the majority of H&P’s fleet is drilling 8,000-ft to 10,000-ft laterals, some operators are reaching for 15,000 ft. He urged manufacturers to improve quality control and equipment uptime, as well as ensure the availability of spare parts. On the new mechanical rigs, we’re upgrading from hydraulic 20,000 ft-lb units to AC-electric powered top drives with up to 30,000 ft-lb of torque.” While high-torque top drives have been in use offshore, a typical 1,500-hp land rig uses a 30,000 ft-lb torque top drive.
The configuration of the newest AC rigs with walking systems provides more flexibility over a skidding system. Additionally, precise control of the rig’s systems allows for the use of newer, more advanced downhole drilling tools to further increase drilling efficiency.
The company saw peak activity during the seasonal Canadian market, with close to 50 rigs operating in the oil-rich Montney, Duvernay and Cardium plays, Saskatchewan, and the Horn River gas basin.
Driven by the needs of operators and today’s operations, drilling contractors are stepping up the capabilities of horizontal drilling rigs. Many of the wells were drilled in an undulating fashion to facilitate re-perforation over time” Mr Smith explained. If any images that appear on the website are in Violation of Copyright Law or if you own copyrights over any of them and do not agree with it being shown here, please also contact us and We will remove the offending information as soon as possible..
Fast moving – walking or skidding – AC rigs with 1,600-hp mud pumps and higher torque top drives are populating the global fleet.
Not only is the development phase of shales driving the trend but so is the horizontal development of conventional reservoirs, such as the Permian. With horizontal drilling, “you expose a lot more reservoir to the wellbore, and it’s particularly applicable where you have thinner zones.



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