For the real estate industry, the mantra is location, location, location. For the drilling industry, it is technology, technology, technology. That is especially true during a downturn in the market due to crude oil prices dropping by half in only six months. As many operators, drilling contractors and service companies have emphasized, this is not their first rodeo.

Downturns in the drilling industry are good for separating the wheat from the chaff. Older rigs are retired, and new rigs continue to work with better efficiency, greater safety and improved effectiveness. Even though the rig count has declined overall dramatically, the number of horizontal rigs is decreasing at a much slower rate. The technology on new rigs makes those much more attractive.

For the horizontal wells in shale plays, walking rigs have pretty much sewn up the market. At the same time, automation in drilling rigs has improved safety and reduced crew size, adding to the value of the technology. It is not just the rig technology that has advanced rapidly. Downhole equipment is much more robust and designed for HP/HT conditions. A new generation of hybrid bits is changing the way wells are drilled.

All of this is occurring while both onshore and offshore rigs are being stacked. However, there will always be a market for highly advanced rigs. The industry knows the value of technology in opening new reservoirs in frontier areas.

Drilling market taking a pounding

Oversupply combined with dropping commodity prices could be a recipe for disaster.

By Blake Wright, Contributing Author

The free fall in crude oil prices, down more than 50% since last June, is putting the squeeze on global drilling markets, with demand for both land rigs in the U.S. and deepwater units worldwide wavering in the looming shadow of oversupply. America’s newly minted leading position as the world’s top oil producer has resulted in the once import-hungry nation bringing in less foreign crude. That fact, coupled with OPEC’s recent decision not to curb its oil production, has placed strong downward pressure on prices, which has started to affect oil company capital spending plans for 2015 and is resulting in a mounting list of deferred drilling projects.

The U.S. land rig count started to slide during the last half of fourth-quarter 2014 and has continued to fall. The drop is a direct result of project economics taking it on the chin from declining crude prices. What works in the Bakken region of North Dakota, for example, at $100-plus per barrel does not necessarily work in that region at $50 and falling. The same holds for areas like the Niobrara in northern Colorado and the Permian Basin in West Texas.

The rig count in the Bakken has retreated in concert with crude prices. This time last year, North Dakota’s rig count was hovering around 200. As of the second week in January 2015, the count was approaching 150 rigs, prompting the state’s top regulator, Department of Mineral Resources Director Lynn Helms, to tell the State Appropriations Committee there is “a little bit of gloom, but no doom” in store for the region’s oil business. Since mid-December 2014, the U.S. rig count as a whole has plunged by 180 units to below 1,700 rigs.

Uncertain environment

Though some of the fall-off is likely seasonal, the rig count really began losing ground around the same time as operators started revealing steep cuts to planned 2015 spending. The uncertain environment is hitting the wallets of producers of every size.

Major explorer ConocoPhillips was one of the first out of the gate with a planned 20% drop in capex for 2015. Global producer Apache expects its spending to be down 15% year-over-year. Texas-based independent Sanchez Energy told investors in early January that it would cut its planned spending by more than half—from $1.15 billion initially to a revised budget of between $560 million and $600 million. Many operators have kept specific spending plans close to their chests as they examine and reexamine the best way forward in 2015.

A recent survey of 200 senior oil executives by Pearson Partners International found 53% expected their companies to reduce their capital spending, while just 18% of participants expected their companies to increase their annual outlay. The sentiment was echoed in early January when investment firm Cowen & Co. released its 2015 spending survey, which found that global spending would fall by 17% on average (with a 22% decline estimated for the U.S. alone). It would be the third-largest decline since 1985.

Land rigs

Land drillers used the boom times provided by the U.S. shale renaissance and higher oil prices of the past few years to launch an aggressive newbuilding cycle designed to both add new higher end alternating current (AC) equipment to their respective fleets and replace older units that are not well suited for the work required by operators in the nation’s shale plays. The Big Three land drillers—Helmerich & Payne, Nabors and Patterson-UTI—hold more than a combined third of the overall market share in the U.S., and each has a number of newbuilds on order.

Since mid-December Helmerich & Payne has had 11 FlexRigs, its premium AC-driven unit, go idle, bringing the number of available FlexRigs to more than two dozen. The company said in early January that spot day rates for the FlexRig fleet had dipped 10% quarter-over-quarter and that it expected another 40 to 50 FlexRigs to go idle prior to the end of February. The driller also confirmed it had received early termination notices related to four long-term rig contracts but did not specify which deals were affected.

The company has ordered 89 new FlexRigs since October 2013. Fifty-five of those units have already been delivered. The contractor currently is building four FlexRigs per month but noted it can speed up or slow down that schedule as demand dictates. Patterson-UTI boss Andy Hendricks told investors in December that the company’s fleet of around 250 land rigs will be two-thirds APEX units by September and added that of the 30 new rigs expected to be delivered over the next four quarters, 22 are contracted, leaving eight units exposed to the slowdown.

“The downturn that we’re moving into, we don’t know what it is going to look like,” he said. “We don’t know how long it is going to last.”

A protracted downturn could reduce newbuild pace to zero. Hendricks added that even a 500-rig drop in the domestic count would still allow for newbuilds to be contracted, but likely at much softer terms.

Investment firm RBC Capital is forecasting a 16% drop in Patterson-UTI’s rig count in 2015 compared to last year. An overall U.S. rig count drop of around 30% is expected.

According to its most recent rig activity report issued in early January, the contractor currently is running 203 rigs in the U.S.

Every land driller appears to be preparing for worse and hoping for the best, with expectations of weak utilization and reduced day rates imminent as programs are deferred and smaller operators manage their cash crunch.

Offshore drilling

Offshore, the story is much the same. Jackup owners have seen assets idled and layoffs commence. Hercules Offshore revealed 300-plus layoffs last quarter as it sidelined four rigs in the U.S. Gulf. Rival Paragon Offshore has roughly half of its jackup fleet committed in 2015, and with lower crude prices and new rigs continuing to come into the market, the contractor, along with others, will face an uphill battle keeping its fleet utilized.

In deeper waters, floating rig contractors have been battling pressures of an oversupply since before the oil price collapse. Day rates for new deepwater fixtures are down and continue to erode from the highs experienced just 24 months ago.

“There are two different dynamics, and they are overlapping here and unfortunately enhancing each other,” said Christian Beckett, CEO at Pacific Drilling. “There was already some viewpoint that the scale of new rig introduction into the deepwater space was probably reaching the level necessary to fully supply the market ... with the risk of oversupply through 2015 and into 2016. I think that was without any expectation of any significant weakening in demand. In my personal view, we [industry] had built and delivered into the market enough rigs to serve the majority of demand through the end of 2016 ... or at least we will once the rigs we have on order are delivered. So we were already in a market where we probably needed to see some level of attrition, old rigs getting retired, to keep the market in balance. The oil price being as volatile as it is, which is almost as important as the absolute price, is creating that much more uncertainty and curtailing some of the demand growth we expected to see. We have really seen demand in the ultradeepwater fall so far. There are as many rigs working now as there were a year ago, but it certainly hasn’t grown at the rate that we anticipated. That’s leading to a rig oversupply.”

The rig overhang impacted day rates for the better part of 2014, even before oil prices collapsed. Leading-edge rates for high-end floating rigs that once flirted with $700,000 are now closer to $400,000.

According to investment bank Tudor Pickering Holt, about 32 new floating rigs are slated for delivery in 2015 alone. Roughly half of those units do not have work commitments. Pacific has one of those units, the drillship Pacific Zonda due in the third quarter. In 2016, another 22 floating rigs are scheduled to join the global fleet, with half of those minus a contract. Couple that with the number of current contract roll-offs and the active sublet market emerging due to operator capex reductions, and the stage is set for available supply to balloon in the coming months.

One way drillers could cushion the blow is to make decisions on fleet attrition. A few contractors have already signaled that rigs will be coming out of the market. Diamond Offshore said last quarter it would scrap six midwater units and take a $100 million-plus charge related to those assets. Both Ensco and Transocean have already taken hefty writedowns, and more drillers are expected to follow suit. Decisions will have to be made by most contractors if some of these older assets hold enough value to maintain and, in some cases, rehabilitate for future use.

“How long is this going to last? That’s the billion-dollar question,” Beckett said. “I think it could recover as early as early 2016 if it is actively managed, and it could take until 2018 if it is not.”

Another question mark on the prognosis for deepwater rig activity is the turmoil in Brazil and the uncertainty regarding the length and breadth of Petrobras’ continued struggles. Embroiled in political scandal, the state-run oil company is the largest end-user of floating rigs in the world. If it stumbles, it could have a knock-on effect. Pacific Drilling has a drillship off Brazil, the Mistral, that it will likely relocate to the U.S. Gulf. The contractor has agreed to an outline of a deal extending the unit with Petrobras, but the ability to transform that into a signed contract is in doubt.

Overall, the international offshore markets have remained flat, with increases in China and the Middle East being offset by drops in Latin America and Europe. Weakness in onshore markets outside the U.S. is led by Mexico, which has experienced some recent volatility. The country’s land rig count dropped by five units in December to 30—its lowest point since the end of 2002, according to investment bank RBC Capital.

With budgets shriveling up and a looming oversupply of rigs, kit specialist National Oilwell Varco (NOV) remains modestly bullish on the longer term outlook for new equipment additions, especially when it comes to deepwater units.

In the 10-year period between 2005 and 2014, 163 drillships were ordered by industry, with 137 deliveries made out of that same period. NOV estimates the next 10 years—2015 to 2024—will produce 207 drillship deliveries.

“It’s getting a little soft right now with short-term capacity issues,” said Joe Rovig, president of NOV’s Rig Systems and Rig Aftermarket segments, at a recent analyst day. “There are a couple of rigs that will get delivered here shortly that will not have a contract. So we’re not seeing the pace of building/orders that we saw before. Bookings will be off in 2015 and will hit our P&L [profit and loss] in 2016. We think this is a short-term issue. Deepwater is going to be a major growing element in the future. Long-term demand continues.”

Once again industry will retrench and realign its assets to manage through a downcycle. Fueled by a fierce flurry of newbuilding and precipitous drop in crude prices, predicting a bottom to the current trough raises more questions than answers. Most pundits do not believe this downturn will be a protracted event, but it will be one marked by layoffs, battered stock prices and industry consolidation.

Building a better, safer rig

New design incorporates automation, safety features and efficiency.

By Walter Bagassi, B Robotics W

More than 20 years ago, B Robotics W began with a blank page when setting out to build a new rig that would be the most productive and safest in the world. The goal was not to make improvements in the design of a conventional rig. Instead, the company started from zero, rethinking every element of a rig to improve performance and safety and reengineering components from the ground up.

The motivation to create the rig stems from the fact that drilling managers often can’t work normal hours because of mechanical breakdowns, not to mention the occasional rig accident. Company founders thought there must be a better, safer way to drill for oil and gas. As time and resources permitted, a small group of engineers at the company worked on the design of the new rig.

It needed to be as productive as possible. A rig’s performance can be measured by the number of wells or total meters drilled per year. The more wells/meters drilled, the more valuable the rig. Variables considered were safety, overall design, drilling and tripping speed, rigup/down time, transport loads, reliability of parts, maintenance, and redundancy of critical components.

Looking to the future, engineers believed that most of the easy oil had been tapped and that drilling would increasingly take place in remote areas, many with severe climates. So they also sought to build a rig that was highly reliable, required minimal maintenance and functioned efficiently in hot and cold weather.

To make the rig safer, workers on the drilling floor and monkeyboard would have to be removed. This could only be achieved by automating elements of the rig. Other industries had adopted automation, and the engineers believed that there was no reason the technology could not be incorporated in a drilling rig.

Changing the conventions

One of the first issues examined was movement of the top drive. For automation to be possible, the stroke had to be manipulated within inches.

Hydraulic cylinders offered the best solution. They have many advantages over a drawworks. This said, they also had to handle at least three Range-2 or two Range-3 drillpipes and collars during tripping, the same as a conventional rig.

After some research, a solution was reached. Rather than push on a cylinder rod to lift weight, a common design on hydraulic drilling rigs, these new rigs lift weight by pulling on a cylinder rod. This configuration, combined with a system of pulleys, makes possible the handling of doubles and triples.

Lifting weight by pulling on a cylinder rod eliminates the dead-end load on a shaft. A 5-in. Range-2 S 135 drillpipe can lift up to 950,000 lb, or 430 tons. In contrast, when pushing weight, the same size shaft on a 10.6-m (35-ft) long stroke can lift only 80 tons.

Drilling pumps

Having decided to use hydraulic cylinders by pulling on rods, designers then turned their attention to pumps. Variable delivery pumps are typically used in combination with hydraulics. The pumps are notoriously delicate and require clean fluid to function properly. Numerous filters have to be changed regularly, and when a filter clogs, sensors shut down the pump, shutting down a rig.

Variable delivery pumps are also difficult to replace. A skilled technician with special tools is required to swap out a damaged pump.

Given these shortcomings, plain gear pumps were chosen, which are highly durable and dependable. They operate when oil is less than completely clean and can even function with water and an additive. Gear pumps are mass-produced and are readily replaced.

Synchronous electric motors were selected to rotate the gear pumps and variable frequency drive inverters to control their speed and torque. Altering the speed of the motors varies the volume of fluid delivered to the hydraulic cylinders, changing the traveling speed of the top drive.

The BQ 400 rig is designed with 12 high-pressure gear pumps, two of which are backups. Maintenance is simple. There is a single easy-to-reach filter for all of the pumps.

To save energy, the gear pumps are activated only as needed. When tripping in to slow a drillstring, fluid from the rig’s hydraulic cylinders is sent back through the gear pumps. This causes them to rotate in reverse and produce electric power to operate the rig’s utilities.

The top drive

After the rig’s basic design was completed, work began on building a top drive. A system was developed to precisely control its movement and guides on the mast to position its shaft, always at well center. The top drive also was shortened to better fit into the mast.

The top drive has two alternating current explosion-proof water-cooled electric motors that produce high torque at low and high speeds (it can operate with one motor in an emergency). It has a splash lubricating system for the inner gears and parts as well as a dedicated hydraulic pump to ensure sufficient lubrication in harsh climates.

Automation

Attention next turned to automating the rig’s components, starting with the monkeyboard. Among the other major elements automated were the slips, layup and down machine, pipe container, roughneck, and subs and bits loader.

The automated systems were designed to automatically handle different size tubulars. Systems also were devised to grip tubulars on center and to ensure tubulars aligned at well center.

A control system was created for the automated elements that is easy to learn and operate. In semi-automation mode, a driller in the driller’s cabin simply turns a switch to activate a step in the drilling process. For example, turning a switch for the automated slips sets them in place. Rotating the switch the opposite direction releases the slips. Another switch is used to position the proper insert faces to well center.

In hands-free mode, a computer program sequentially activates the steps of each automated system. Once a driller sets the depth to drill and start the hands-free program, there is no need to touch another control. The rig automatically starts and stops pumps; breaks and makes connections; adds tubulars as necessary; and increases/decreases the rpm of the top drive, weight on bit, etc.

When tripping in, the rig pulls three Range-2 pipes from a well and stops about 1.2 m (4 ft) above the rig floor. The rig sets the slips, breaks a connection and then parks the stand on the monkeyboard. It then repeats the operation without the intervention of a driller.

At any time in the process, the driller can switch from hands-free to semi-automation mode.

In hands-free mode, the rig trips in and out at 1.5 m/sec (5 ft/sec) compared to about 0.6 m/sec (2 ft/sec) on a conventional rig.

In addition to the rig’s automation, there are numerous other important features of its design. For example, all of the rig’s critical components have backup systems. Elements of the rig are designed for easy transport and self-unloading. All of the hydraulic, electrical, pneumatic and fluid lines are pre-assembled or integrated into swing arms or suitcases for quick connection and disassembly.

It has been a long road to develop a better, safer drilling rig, which has been named Genesis. But the company is not stopping here. Current projects include automating the mud system so that the rig can be operated remotely.

Successful deployment of toe sleeve makes impact in Anadarko Basin

Design optimizes production, adds flexibility and reduces costs.

By Rodney Long, PetroQuip

As second-quarter 2015 approaches, many in the industry remain optimistic that oil prices will soon recover, while others fear the worst is yet to come. No matter where operators fall in the broad spectrum or how high or low oil prices rise or fall, there is always a need to develop advanced technologies that maximize production and reduce or eliminate excess costs. This is especially true as the demand for longer horizontal wells with multiple frack zones continue to become the norm in today’s drilling environment. The low-hanging fruit of the oil and gas fracturing industry are gone, along with the days of drilling vertical wells at shallow depths. As a result, more advanced technologies that maximize profitability are essential for operator success.

Challenges of toe sleeves

With the focus on reducing nonproductive time, enhancing safety (both operational and environmental), and eliminating or reducing costs, PetroQuip Energy Services LLC is focusing its pressure control expertise gained in the offshore market to onshore operations where continuous challenges associated with traditional toe sleeves have been leaving operators at risk of leaks or system failures.

As the company transitioned into the onshore market with its sliding toe sleeve, it learned that operators were losing production time by first using coiled tubing (CT) to initiate circulation in a well and then installing traditional toe sleeves. These toe sleeves do not allow operators to test the system’s integrity for as long as desired, or these tests can only be completed up to 80% of the equipment’s rated pressure and never to maximum pressure.

It is simply an archaic way of working since no one knows whether the toe sleeve can or will maintain a proper test pressure in a well, and if it doesn’t, then proceedings have to be put on hold or the operator has to settle for nondesirable test results. Operators simply can’t afford to compromise or lose time when considering what it costs per day to drill, and it’s a risky way to work--there are no guarantees.

The stress of uncertainty combined with the need for well intervention services make a costly investment for any operators working within the hydraulic fracturing environment. CT is a very expensive way to run the first stage—the toe stage of a completion. PetroQuip’s solution eliminates the need for CT on this first stage altogether while providing reliability, project flexibility and complete operator control.

Operators traditionally seek the answers to four fracking operation casing test questions before using a new toe sleeve. Questions include:

  1. How high of a pressure test can be achieved?
  2. How long can that pressure be tested?
  3. How many test pressure cycles can be conducted?
  4. How soon after testing does the toe have to be opened?

While there are toe sleeves that provide satisfactory answers to one or two of these critical questions, operators have been left without a tool that adequately covers all four situations.

A unique opportunity existed to rethink the drilling process and the equipment that is currently used. The BigFoot toe sleeve addresses all the issues that customers currently face in today’s shale applications.

Successful installation

PetroQuip began working with customers to survey their specific needs while implementing the discoveries into the design of BigFoot. In fourth-quarter 2014, PetroQuip ran its sliding toe sleeve in a horizontal completion in the Anadarko Basin. Initial circulation/first hydraulic fracturing was done directly through PetroQuip’s BigFoot toe sleeve in lieu of using CT. This operation was performed in 8.75-in. open hole using 5.5-in. casing with 5.5-in. 20# CDC casing threads. The well had a true vertical depth of 3,191 m (10,469 ft), a measured depth of 4,677 m (15,343 ft), a bottomhole temperature of 104 C (220 F) and a casing test pressure of 9,500 psi. BigFoot itself was a 5.5-in. P110 sleeve rated to 18,000 psi with a maximum test pressure of 13,400 psi and sleeve open pressure of 4,600 psi.

BigFoot was installed and cemented in place in early November 2014. Eight days later, the operator rigged up to test the casing with a test pressure of 9,500 psi being applied to the casing and held in place for 30 minutes. The casing pressure was then bled down to zero psi. Once the first casing test was successful, the operator chose to cycle through the remaining casing test chambers by pressuring up to 8,500 psi and then bleeding to 0 psi. On the final cycle the sleeve was opened at 4,600 psi. The operator then pumped into the formation with an injection rate of 11.5 bbl/min at 7,200 psi. A total of 150 bbl was injected before shutting down.

BigFoot enables operators to run multiple tests at any maximum or desired pressure for as long as is necessary. The toe sleeve can also be opened at any time. These features satisfy all four fracking operation casing test questions.

This capability also can be coupled with the optional additional feature of having multiple high-pressure tests and then opening at a lower pressure. In this particular example, the tool was prepped with two high-pressure cycles (9,500 psi) and set to open at a much lower pressure (4,600 psi).

Since the initial success of BigFoot, the operator has chosen to run it continuously as it moves forward in 2015.

“The successful installation and operation of BigFoot is directly related to our careful attention to the operator’s needs and the specific application,” PetroQuip president Bill Darnell said. “Since no two reservoirs are the same, we took the time to truly understand what our customer was dealing with. We were asked to design a toe sleeve more reliable and flexible than others in the industry, one that would enable operators to test their systems as many times as they needed for as long as they needed and at any pressure they required.”

Mapping complex reservoirs while drilling

Uche Ezioba and Mauro Viandante, Schlumberger

The GeoSphere reservoir mapping-while-drilling service was developed to improve operators’ understanding of their reservoir beyond the first few meters of the wellbore. The service represents a step-change in LWD technology, combining a much deeper depth of investigation (DOI) of more than 30 m (98 ft) with a new automated stochastic inversion engine. To increase the DOI, new hardware and software designs were developed. The hardware development was in the introduction of new lower electromagnetic frequencies (less than 100 KHz) and a modular bottomhole assembly design to increase spacing between transmitters and receivers.

The DOI of an electromagnetic tool is governed by three factors: the spacing between transmitter and receiver(s); the frequencies used, with a lower frequency reading deeper than a shallower one; and the resistivity/conductivity contrast of the layer the tool is in with respect to detecting layers.

The unique DOI of the tool enables detection of multiple resistivity layers that correspond to different geological interfaces (variable qualities of the reservoir matrix, overburden, underburden, fluid contacts with resistivity contrast), or both over long horizontal distances. The service provides information at a scale that bridges the gap between surface seismic resolution and measurements obtained at the borehole scale, adding important new pieces to the reservoir characterization puzzle.

The mapping information delivered from the service can be integrated into an operator’s 3-D reservoir and geological models to optimize the drilling operations and completion designs of a current well and help optimize production improvements and long-term field development strategies. In real time, reservoir maps from the GeoSphere service can be exported into E&P software platforms, where experts can create 3-D displays with formation evaluation data attributes to enhance the evaluation of layered formations.

An operator in the Otway Basin offshore southeast Australia needed to map a complex reservoir with discontinuous sands and anticlines to position drain trajectory and steer aggressively to connect discontinuous sand bodies. The operator used the GeoSphere service’s deep directional electromagnetic measurements to improve reservoir interpretations, land wells and make real-time steering decisions. The operator successfully mapped the reservoir layers, landed wells in gas sands without drilling sidetrack and kept the wellbore within the reservoir.

The reservoir mapping-while-drilling service has been successfully tested in more than 165 field operations in the North Sea, Europe, Russia, North America, South America, Australia and the Middle East.

Focusing on new technology

Don Henderson, Tesco Corp.

New technologies must be able to eliminate costly equipment, improve safety and enhance operational efficiency as needed no matter the price of oil, a fact that is clear to both operators and service providers. Working closely with operators has given Tesco the insight to understand the needs of its customers during the oil market’s ups and downs.

As a result of the sale of the casing drilling business in 2012, Tesco Corp. has been able to redirect its research and engineering (R&E) funding to its products and tubular services businesses. “Our emphasis on innovation has always been a focus for Tesco, and in fact there will be an acceleration of new technology deployments as a direct result of finding new solutions to optimize drilling efforts,” Tesco CEO Fernando Assing said.

Tesco has been using its proprietary casing drive system (CDS) with its tubular running service teams successfully for more than a decade, and the CDS is still recognized as the premier casing running tool in the market. This tool inspired Tesco’s engineers to develop the first drillpipe drive system (DPDS). Commonalities between the two exist in that they are both safe and simple to use. Both tools are also fast, and both are able to fully engage into either a joint of casing or drillpipe within five seconds without ever having to thread into the joint. Designed to match the top drive’s performance, Tesco envisions the DPDS will operate at 200 rpm, lift up to 500 tons and torque up to 100,000 ft-lb, all while maintaining a fluid bore pressure of 7,500 psi.

Another new product under development is a device for making and breaking connections on the rig floor using only the power of the top drive. Simple, robust and safe, this new tool acts as a torque multiplier, allowing for connections to be made up without using tongs, spinners or iron roughnecks. Leveraging the power of the top drive eliminates the need for a separate power supply for an iron roughneck and integrates the control of the new device into existing top drive control panels. Tesco’s goal is to transform the rig floor into a safer, near fully automated environment during drilling and tubular running activities. Technology of this type represents a step-change in rig floor mechanization, and it is more than the simple automation of the current manual processes. Accordingly, these products require extensive engineering work and take significant testing to develop.

Doug Greening, vice president of engineering at Tesco, explained, “Breaking a tool joint on the floor without breaking the intermediate joints and doing it by harnessing the power of the top drive is a great example of thinking beyond what more can be done with a set of tongs. This is not evolution; this is revolution.”

“The guiding principle for R&E in Tesco is the automation and mechanization of the entire pipehandling process, including tubular running and other rig floor operations. This will not only improve safety, but will also introduce efficiencies and reduce nonproductive time simultaneously. The effective interplay of these factors is the single-most important consideration for our clients,” Assing added.

“We have seen many cycles in the past, and some of the best ideas and technologies in the industry were developed as a result of the pressures and challenges faced during those difficult times. It’s these times when differentiating from the competition becomes even more critical.”

In 2009, despite a North American rig count reduction of 40%, Tesco achieved a record number of proprietary jobs in each quarter.

“In a thriving market, everyone is very busy,” Assing said. “Introducing new technology is not risk-free, and no one wants to be the first. The current market cycle will provide some imaginative players with unexpected opportunities. For our part, this means accelerating the deployment of our technologies geared toward differentiation and the creation of real value.”