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| Among the technologies that have accelerated with the factory-style approach intrinsic to shale drilling is the use of remote operation facilities to monitor real-time performance on critical, unconventional well applications. Photo courtesy of Baker Hughes. |
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Sobering reports of rig site accidents and growing scrutiny over E&P-generated waste streams deliver cautionary messages to the unconventional plays, where textbook efficiencies continue to delineate well construction.
While multi-well pad drilling and other technology-driven efficiencies have doubtlessly reduced the overall HSE footprint, myriad safety and environmental issues continue to put many of the shale plays squarely in the public and regulatory crosshairs. The industry, to be sure, has responded accordingly, as reflected in the recent development of safer, less waste-inducing technologies, among them remote pipe racking, which essentially renders the “derrickman” a misnomer, water-based drilling fluids incorporating nanotechnology, and fluids cycle automation.
Joining in the wave of new HSE-directed innovations, the public and privately-funded Environmentally Friendly Drilling (EFD) program is conducting field trials, aimed at providing unbiased research into the technical, economic and societal feasibilities of candidate technologies to address distinctive air, water and land issues, Fig. 1. Within its wide-ranging Technical Integration Program (TIP), the EFD initiative works with industry, academic, governmental and environmental representatives on a host of studies, including unprecedented tailgate emission studies to validate gas-fueled drilling technologies; evaluate the onshore environmental benefits of dope-free pipe connections; advance the use of longer-drilling aluminum drill pipe; and promote lightweight U.S. Department of Transportation (DOT)-certified drilling rigs to reduce roadway damage.
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| Fig. 1. The Texas A&M Global Petroleum Research Institute (GPRI) analytical lab on location in the Eagle Ford. The unit is being used in a RPSEA research project to determine the best technology for re-using and recycling make-up and produced water. (photo courtesy of the Environmentally Friendly Drilling program). |
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Richard Haut, Ph.D., manages the EFD program, which is administered through the Houston Advanced Research Center (HARC) of The Woodlands, Texas. “Our emphasis is on getting all the stakeholders involved, and reach a consensus that this stuff, does indeed, address environmental issues. Of course, at the same time, someone's got to save money, and someone's got to make money,” Haut explained.
In no application is that economic reality more apparent than in shale drilling, where only optimizing HSE takes precedence over lowering costs. Consequently, the unconventional plays have spawned a host of celebrated technologies, highlighted by AC-powered rigs with inter-pad walking/skidding packages that have fueled a factory-style approach that is yielding impressive productivity improvement.
“Across all our shale plays, we will drill 23% more wells per rig this fiscal year than we did last year,” said Derek Cardno, BHP Billiton’s V.P. of Drilling and Completions.
FAMILIARITY BREEDS EFFICIENCY
Cardno said that having a wealth of new technologies available becomes doubly valuable when combined with play-specific insight. BHP Billiton has learned that, full well, within the aggregate 1.5 million net acres it holds throughout the Eagle Ford, Haynesville, Permian basin and Fayetteville shales. Though universal homogeneity is certainly not a characteristic that can be remotely applied to the shale plays, one constant for every operator, in every basin, is intense pressure to hold down costs. “Unlike deepwater, where you spend money to deliver time and cost-saving efficiencies, in this game you have to be low-cost,” Cardno said.
Owing to its early mover positions, BHP has recorded some of its most impressive cost-reducing drilling efficiencies in the Eagle Ford and Haynesville. The 17 H&P FlexRigs that BHP is running in the Eagle Ford had drilled some 15 wells of 12,000-ft total vertical depth (TVDs) at considerably under $3 million/well, Cardno said. “We’ve drilled several wells with 15,000-ft runs from surface casing to TD, and used the same assembly to drill the intermediate section, build the curve and drill the lateral. And, this is in the toughest part of the Eagle Ford, which is deeper, with high temperatures that require we really pay attention to the set-up of our mud motors and the parameters we run.”
He singled out the Haynesville, however, where BHP Billiton is operating three advanced Nabors’ Pace-X walking rigs (Fig. 2), as recording some of the most impressive results per capita. “These rigs are spec’d for the type of wells we're drilling there, which are deep, with long laterals and small hole sizes,” he said. “We focus closely on rig moves, and even though these rigs have about double the loads of the H&P Flex 5 rigs, we are moving them in about the same time.”
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| Fig. 2. A Nabors Pace-X rig on contract with BHP Billiton making hole in the Haynesville shale while surrounded by a sound barrier (photo courtesy of BHP Billiton). |
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On the other side of the efficiency equation, Cardno said BHP’s experience in the Permian clearly reflects the trial-and-error that characterize initial entry into any basin. “When you first go out there, your earlier wells will always be your worst wells. It takes time to focus on an area and fully understand what you need to do, and what works well. In the Permian, we have a huge acreage position spread out across the Midland and Delaware basins, and it’s taken us a while to get our arms around it. We have since narrowed our focus in the Delaware basin, and now, we’re getting repeatable results. We’re concentrating on repeatability and plan to begin pad drilling this year.”
Getting to that point, however, has required more than a little experimentation, as reflected in BHP’s attempts to alter its Permian casing designs. “We started running four strings and decided to see if we could drill them with three strings. We could get some of the wells down with three strings, but we were having so many problems that we actually were drilling our four-string wells cheaper. So, we decided to drill with four strings, get really efficient and repeatable at it, and later go back and see if we could eliminate a casing string.”
Continuous improvement is a constant throughout the BHP operations in the shale plays. “For instance, one area we’re really focusing on is our cementing programs. If you think you can drill a horizontal well and achieve proper isolation without good cementing practices, you’re kidding yourself. Also, our engineers have focused on each hole section, each activity, and getting very sharp on continually improving every single part of the well.”
However, Cardno emphasized that drilling efficiencies take a back seat to enhancing safety, particularly when it comes to eliminating rigsite conditions that precipitate catastrophic accidents and optimizing well control. “We have put a huge focus on well control and adhering to good well control practices, Cardno said. “We continually audit our operations, and make sure all our equipment and procedures are in good shape. We still don’t have the consistency that we’re striving for, but we're in much better shape than we were.”
One area ripe for further investigation, he said, is developing a full-proof solution for the inaccuracies, discrepancies and other problems often seen in traditional trip sheets. Ideally, he believes that trip sheets should be built into the driller’s controls, automatically updated with real-time trip tank data, and set to alarm when hole fill and displacement are incorrect. “That would eliminate some of the basic errors we see. It’s a matter of catching things quickly before they become big problems. That’s one area that we possibly could automate, somewhat.”
AUTOMATING FLUIDS CYCLE
To that end, one strategy that holds enormous potential for optimizing both well control and the efficiency of unconventional drilling programs is the automation of key components of the fluids cycle, says Jason Norman, managing partner of Houston's OnSite Integrated Services. Norman co-founded the company in January 2013 after working on drilling automation initiatives at Shell, Chevron and, more recently, Apache.
At OnSite, Norman focuses on the drilling fluids cycle, where proprietary patent-pending diagnostic software is combined with Coriolis metering technology to measure and interpret flowrate, density, mass flowrate, and temperatures going in and out of the well—all in real time. Norman said incorporating process control functionality is particularly helpful in identifying early kick detection, by allowing the driller to instantly distinguish between a kick and ballooning.
“The bottom line is, rather than having the driller unable to determine if the well is ballooning or taking a kick, if you have a well control package and process control that’s not driven by human beings, you can remove all doubt from an incident. Early kick detection is extremely vital, as kicks cost so much to deal with. Even if it's a kick that is controlled, they have to circulate it out, and that takes rig time and leads to NPT (non-productive time).”
Along with kick detection, automated process control of the fluids cycle can go a long way toward improving efficiencies and eliminating the costs of unnecessary sweeps and other preventative measures that have become standard inclusions in many authorizations for expenditures (AFE). Rather than pumping a periodic sweep as a matter of course, Norman said data generated from Coriolis meters placed strategically on the flow line, as determined by a rig survey and analyzed through diagnostic software, provide a definitive snapshot of hole cleaning efficiency, Fig. 3.
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| Fig. 3. Coriolis meters placed strategically on the flow line deliver measurements, both in and out of the well, on flowrate, density, and mass flowrate, with the ensuing data used to infer a number of diagnostics, including hole-cleaning efficiency. Photo courtesy of OnSite Integrated Services. |
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“We infer some diagnostics from the data we receive,” he said. “We can determine hole cleaning efficiency, sweep efficiency, and mud pump efficiency, and we can monitor losses and provide data on the severity of those losses. This also allows us to detect the difference between ballooning and a kick. We do that by looking at the signature of the data on every connection, so we can look back and determine if this is a normal flow-back signature or an abnormal signature.”
“In many cases, we’ll see drilling programs calling for sweeps every 500 ft to 1,000 ft, whether they need it or not, because ‘that’s the way we've always done it.’ Many drillers might also go two to eight times bottoms-up, and you ask them why and, again, they’ll say that’s the way they’ve always done it. On many Eagle Ford operations, they may routinely pump six to eight times bottoms-up. What we’ve done is develop a clear-cut means of determining the effectiveness of remedial hole cleaning and not just a gut feel.”
Once the diagnostics have established a clean hole, Norman said examination of the mass balance circulation can determine the amount of circulating time necessary prior to pulling out of the hole. Graphical representations of the measurements gives the driller clear evidence of the rig time being expended by circulating needlessly. Norman said a number of drilling contractors have wholeheartedly embraced the instrumentation concept. “They recognize that this (automation) will become commonplace in two to five years’ time, whether it’s instrumentation at its basic level to just measure flow and density going in and out of their well, or doing the whole enchilada with automated mud mixing, salinity, water cut, particle size distribution, and what have you. At a minimum, everybody will be doing flow and density. It’s just the right thing to do. It's a cheap insurance policy to maintain a good safety record.”
REDUCING WASTE STREAM
Minimizing the waste generated at the rig site begins with the formulation of the drilling fluid. While many operators prefer the lubricity, inhibition and other performance characteristics of oil-based mud, use is trending more toward water-based drilling fluids, where the resulting cuttings, unlike those produced by their invert emulsion counterparts, are approved for onsite discharge or can be converted to road grading and other beneficial reuse applications.
“We’ve been running oil mud, but we’re going to start experimenting with water-based mud,” Cardno said. “Obviously, the prize is reduced disposal costs, but we have to balance it and determine whether we’ll give up anything in terms of ROP and inhibition. If we can drill just as fast and save on disposal, that may be the cheaper way to go.”
Nearly all the drilling fluid companies lay claim to aqueous-based fluid systems that they say meet those criteria. NOV FluidControl, for one, said an evaluation of more than 156 Eagle Ford wells that employed its PolyTrax water-based drilling fluids system showed average ROP equaling those of oil-based mud offsets, with dramatic decreases in waste volume and overall well costs. “Besides reducing well costs, we’re also not continually filling up a pit on somebody’s ranch with oil-based mud cuttings,” said Operations Manager Carl Tolbert.
M-I SWACO, a Schlumberger company, is focusing on developing onshore, synthetic-based drilling fluids, using readily biodegradable linear paraffin as the base fluid, as well as advancing nanotechnology in water-based mud to enhance wellbore stability and reduce the waste volume.
“We’ve been pursuing onshore synthetics, parallel with what we are doing with synthetics offshore and many of the same issues are at play. Certainly, one of the key issues is the base fluids, which are driven by availability that changes as manufacturers change their product mix,” said M-I SWACO Manager of Environmental Affairs John Candler.
Candler said a prototype synthetic-based mud (SBM) introduced in the Marcellus shale delivered impressive results in balancing the high inhibition and other performance characteristics of a non-aqueous—based mud with the environmental benefits of its water-based counterpart. Linear paraffin demonstrates excellent onshore performance, both from bioremediation and toxicity perspectives he said, adding that new testing criteria for evaluating onshore SBM is now under investigation.
M-I SWACO also is advancing nanosilica-based products for water-based muds to physically, rather than chemically, block water intrusion into shales. By enhancing the shale inhibition of water-based drilling fluids without the use of chemicals, the nanoparticles not only improve wellbore stability, but reduce the waste volume generated at the rigsite, Candler said.
Essentially, nanoparticles provide wellbore stability by mechanically plugging pores down to a few nanometers in size, effectively decreasing the permeability of the older and more non-reactive shales normally deposited in the production zones. “That combination reduces the waste generated and improves the efficiency of getting the hole down,” Candler said.
M-I SWACO also introduced the RHE-USE solids control technology that relies on mechanical and chemical separation of ultra-fine low gravity solids (LGS) from invert emulsion drilling fluids, allowing operators to reuse oil-based drilling fluids over multiple wells, without the need for high rates of dilution, says Michael Joling, a technical services engineer and project manager for M-I SWACO Environmental Solutions. The company claims the technology has been proven to reduce solids below 1% while drilling.
FINGERTIP PIPEHANDLING
With the intrinsic hazards of pipehandling representing a prime opportunity for improving onshore rig safety, several attempts have been made over the years to develop remote pipe racking technologies that would place the derrickman on safe ground. A spate of derrickman-related accidents early in the shale drilling boom accelerated development efforts to engineer a safer pipehandling system and one that would not compromise the consistent tripping speed and efficiency of manual operation.
After the development of a prototype machine and extensive field tests in the Barnett Shale, NOV, working in conjunction with a drilling contractor, unveiled its fingerboard-mounted Stand Transfer Vehicle (STV), allowing the one-time derrickman to replicate manual pipe-handling operations, but do so alongside the driller on the rig floor, Fig. 4. The machine effectively stages drillpipe and drill collars through manual hydraulic control from the fingerboard and remote control from the driller’s cabin.
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| Fig. 4. The easy-to-operate Stand Transfer Vehicle (STV) allows remote pipehandling with the derrickman out of harm's way. (photo courtesy of NOV). |
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“The STV has been one of our best new products ever, as far as performance in the field is concerned,” said Joel Heinen, product technical manager for NOV Rig Systems and Aftermarket. “It’s done a really bang-up job, and now customers have been using it long enough that we’re getting repeat orders. The real success story has been in its acceptance by other contractors.”
Heinen said that despite its operational simplicity, the remotely controlled pipe-handling machine has thus far demonstrated manual-like tripping speed and efficiencies. “We’ve seen tripping speeds in line with an experienced derrickman. We’re continuously completing field time studies to further validate the data.”
“The modular machine does not rely on complex encoders for position control, and instead employs a dual camera and monitor system to deliver visual feedback,” Heinen said. One camera is mounted on the guide arm where it tracks the guide head along its path in and out of the fingerboard and to and from well center. The other fixed camera provides a well center view of the pipe transfer between the STV and elevator. The cameras and monitors deliver immediate verification of the operation to the operator’s joystick and switch commands, reducing considerably the learning curve for training.
“Since it’s driven by sight and not a computer, you can walk right up and start using it,” said Sales Director Tom Yost. “Since the derrickman sits right next to the driller, when the driller goes on break, the derrickman sits in the driller’s chair. When the derrickman goes on break, a roustabout can operate the STV. If the machine goes down, the crew fixes it or you can revert to manual operations. So, this is a very unique machine. It’s just taken awhile for people to adopt the technology.”
OPPORTUNITIES REMAIN
Impressive efficiency gains notwithstanding, it appears more technical improvements are within reach. Baker Hughes, for example, recently introduced its Navi-Drill Ultra-Curve drilling motor that it says features a differentiating reduction in bit-to-bend length that optimizes high-rate curve building. “The optimized geometry of the Navi-Drill Ultra Curve motor helps maintain a constant tool-face while drilling the curve, resulting in more consistent build-up rates and improved rates of penetration while sliding,” said Alfred Knipper, product line director of Directional Drilling Systems.
BHP’s Cardno said a prime opportunity also exists for the development of a cost-effective rotary steerable system, capable of handling the rigors of high-speed, short-radius horizontal shale drilling. “These are very clever and expensive tools, but when you put them in a really tough environment like the shales with high build rates, they typically come out destroyed, and you end up spending too much. I would love to see rotary steerable become cost-effective and sufficiently durable for these plays,” Cardno explained. “I think we’ve just started to really tap into some of the efficiencies that are still out there.” 
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