Drilling the unconventionals: Shale focus shifts to increasing IP rates, EUR
Productivity is the name of the game in drilling, as new, well-pad-oriented rigs, beefed-up tubulars, tighter spacing, and other factors come into play.
While the near-mythical acceleration in new shale-directed drilling technologies continues to spawn considerably more wells, with fewer rigs, some now question whether operators may be drilling too fast for their own good.
The same well-documented technical breakthroughs that allow 20 or more wells, with ever-increasing lateral lengths, to be constructed quickly, and often repetitively, from a single pad, may also be contributing to reserves being left behind the pipe, they say. Even the primary developers of geosteering, rotary steerable systems (RSS), MWD/LWD packages, and similar technologies that helped germinate the remarkable escalation in unconventional E&P, contend that the hetrogeneity and complexity of many shale plays do not necessarily lend themselves to the wholesale, factory-style approach to drilling that they helped create.
“I can drill one well here, and a quarter-of-a-mile away, it looks like I’m in another state,” Baker Hughes CEO Martin Craighead told the Houston Chronicle on Feb. 16. “What a lot of our customers are finding out is, if you drill wells that aren’t that effective, the last thing you want to do is go into a ‘manufacturing’ process. All you’re going to do is drill more of them faster,” he said.
Meanwhile, even as new-generation, AC-powered “walking” drilling rigs deliver more oil and gas per capita than their predecessors, and at appreciably lower costs, optimal reservoir drainage requires not just drilling longer laterals faster, but ensuring that they are hitting the sweetest spots in what often is a geological hodgepodge. In other words, before drilling several closely spaced wells, which are then completed with equally close fractures, it is imperative to fully evaluate proper wellbore placement and frac treatment design, says Halliburton. Late last year, the company introduced its so-called CYPHER seismic-to-stimulation service, which Halliburton describes as an integrated, multi-disciplinary approach to the drilling and development of unconventional plays.
“In essence, it tells you where to drill, where to land the well, how to complete the well and where to complete the well. Our two enormous value drivers are increased production and reduced uncertainty,” said Stephen Ingram, Halliburton’s North America technology and marketing manager, when unveiling the service at the company’s analysts’ day in November.
There is no doubt, however, that technologies—from advanced pad-drilling rigs (Fig. 1) to remote monitoring capabilities that helped foster repetitive batch drilling—allowing wells to be constructed much like gadgets on an assembly line, have also played chief roles in relaxing the notoriously tight economics intrinsic to shale plays. With once-impressive production rates tending to drop off sharply in some plays, operators’ strategies have been to drill a lot of wells and initiate production post-haste. With many now believing the development of new drilling technology has neared a plateau, R&D initiatives are turning more from enhancing well construction efficiencies, to stimulation and completion, to increase both the initial production (IP) rates and estimated ultimate recoveries (EUR) in what Credit Suisse has labeled the Shale Revolution II. “Clearly, the low-hanging fruit has been picked,” said Halliburton CEO Dave Lesar of drilling efficiencies, when announcing fourth-quarter earnings.
That certainly is not to say that all the drilling technology gaps have been closed. Developers continue to struggle, for instance, with beefing up downhole tubulars and connections, to withstand the higher loads of high-speed and longer-reach drilling.
BHP Billiton is the first to agree that maximizing drilling efficiencies must be accompanied by an increased emphasis on taking a more studied approach to play development. “This is a business that looks a lot like a manufacturing operation, driven by efficiency, repetition and advancements in technology,” said Tim Cutt, president of BHP Billiton’s Petroleum and Potash business group, in December. “What you don’t want to do is go so fast that you drill it all up and complete it before you know the optimum spacing or fluid characteristics.”
MORE FROM LESS
While the high-octane approach to drilling may be leaving reserves untapped, each active rig continues to deliver more oil and gas from shale reservoirs, according to the U.S. Department of Energy’s (DOE) Energy Information Administration (EIA). In January, EIA released its first monthly drilling productivity report that tracks per-rig production in six key U.S. shale plays, Fig. 2. According to EIA, the analysis combines the most recent tally of total active drilling rigs, with estimates of drilling productivity and estimated changes in production from existing oil and gas wells, to estimate monthly production swings.
To keep it manageable, the productivity report covers only the Eagle Ford, Bakken, Marcellus, Permian basin, Niobrara and Haynesville shales. Owing largely to the combination of horizontal drilling innovations and multi-stage fracing, the actual aggregate list of new shale plays grows steadily, with new prospects often cropping up in older, vertically drilled fields once considered drained of commercial reserves.
As expected, the latest report shows the Bakken again at the forefront for new-well oil production per rig, with an estimated 486 bpd/rig expected to be produced in March, up from the 330 bpd that each rig delivered in March 2013. The Eagle Ford is a close second, with projected per-rig production of 452 bpd in March, compared to 337 bpd/rig produced in the same month last year. The Marcellus was by far the year-over-year leader in gas production per rig, with 6.4 MMcfd estimated for March, compared to the 5.0 MMcfd/rig a year ago.
In releasing its latest monthly update, EIA said that new completion and fracing technologies and processes, in short order, likely will render its current projected production increases per rig obsolete. “Exploration and production companies are drilling many wells and constantly experimenting with new techniques to hydraulically fracture the tight formations,” said the federal agency in a statement. “Technological innovation may cause a faster rise in drilling productivity than currently forecast.”
Consequently, EIA says it expects total U.S. onshore oil production to surpass its estimate of 5.7 million bpd for 2013, and reach a forecasted 7.1 million bpd by 2015.
According to Baker Hughes, a total of 1,053 rigs was active, as of Feb. 18, in the six targeted plays, compared to the 1,062 rigs making new hole at the same time a year ago. At the end of the fourth quarter, Baker Hughes data also showed 5,187 new wells being drilled in the six plays, compared to 4,571 fresh wells in the same quarter a year prior. Interestingly, of the six plays targeted in the EIA drilling productivity report, the geologically complex DJ-Niobrara of Colorado saw the largest year-over-year increase in rig count (53 active rigs in February 2014, compared to 39 in the previous February), but recorded fewer new wells drilled, with 258 new wellbores constructed in fourth-quarter 2013, compared to 311 in the like period a year earlier. Baker Hughes data showed a total of 9,056 onshore wells drilled in the U.S. at the end of the fourth quarter, a 5% jump over the 8,658 new wells drilled in all the developed and emerging shale plays during fourth-quarter 2012.
EIA Administrator Adam Sieminski said the data more than confirm that enhanced drilling efficiency, coupled with new-well productivity, contributes considerably more to overall production growth than an increased rig count. “The next phase of the shale revolution will be using 3D seismic to determine which sections of multi-stage frac jobs will be most productive. Companies are just beginning to get into this,” he said.
NEWBUILDS HITTING MARKET
Despite the lower rig count, contractors continue to restructure their fleets around new-generation rigs designed specifically for the unique demands of multi-well pad drilling, Fig. 1. The developers of advanced AC-powered rigs, with inter-pad walking packages, which command comparatively premium day rates, are awaiting the arrival of a host of newbuilds this year, as the days of rigging-up, rigging-down and trucking to a new location quickly evaporate, onshore the U.S.
During the first quarter, Helmerich & Payne said it had already taken delivery of 24 new FlexRigs, with another 22 on tap to hit the market during the current fiscal year. The 35 new rigs, either delivered or under construction, are all under contract with nine different operators, according to H&P. Elsewhere, Nabors Industries said that three of its new PACE-X walking rigs arrived out of the shop in early 2014, with another eight under construction and scheduled to be ready for work later in the year. “However, we believe we could deploy even more into the field, if we have them ready to go,” said Nabors Chairman and CEO Tony Petrello, who, at the end of 2013, said the contractor recorded fourth-quarter earnings that “exceeded our expectations.”
Last year, Patterson-UTI increased, to 124, its fleet of APEX high-specification AC rigs, said Chairman Mark Siegel, who added that the rigs achieved better than a 95% utilization rate. Like the competing FlexRig and PACE-X, operators are drawn to the proprietary APEX design for its capacity to quickly “walk” between wellsites on a drilling pad. Patterson-UTI says the average “walking time” for an APEX rig is 45 min. for 10-to-15-ft well spacing.
Over one year, BHP’s Cutt said that the steady conversion of much of the operator’s contracted fleet to the H&P FlexRig has played a prominent role in cutting Eagle Ford drilling costs from around $5 million/well to roughly $4 million/well. “The reduced drilling time between wells, with these new rigs and the overall efficiency, is really paying out,” he said during the December media gathering in Houston.
Of course, the key driver of the lower per-well drilling costs is the average time from spud to TD, which continues to drop steadily, even with laterals that show no sign of becoming shorter anytime soon. By way of illustration, consultancy DTC Energy Group said that lateral lengths in the Bakken shale doubled over five years, going from an average of 5,000 ft in 2008, to around 10,000 ft last year. Even with the additional 5,000 ft in lateral wellbores, DTC Energy says 21,000-ft, TD, Bakken wells are now being drilled in 18 days, on average, with some being ready for completion in 12 days. In 2008, when the Bakken was emerging and beginning to take on a life of its own, a 16,000-ft, TD, well required upwards of 32 days to drill, according to the DTC group.
Corroborating the DTC analysis, Marathon Oil said, as of the end of 2013, that it was drilling Bakken wells to more than 19,000 ft, TVD, in 15 days. In first-quarter 2012, Marathon said those same wells required 22 days from spud to TD.
The general consensus has the U.S. onshore rig count remaining flat this year, but investment banking firm Raymond James raised its horizontal rig forecasts from an estimated 6% annual growth to 11% growth. Raymond James analyst J. Marshall Adkins said the increased projection was prompted partly by the faster-than-expected wholesale switch to horizontal drilling in the Permian basin, and the substantially colder winter that has elevated gas prices to a five-year high. “Stubbornly high oil prices, better efficiencies and lower costs have allowed U.S. E&P cash flows to remain stronger than we had previously modeled,” he added.
In addition, a growing number of those rigs are being fueled by natural gas (Fig. 3), which not only takes advantage of abundant supplies, but also cuts both costs and operators’ environmental footprints. Canada’s EnCana has been a pacesetter in the conversion to LNG-powered rigs, as well as introducing dual-fuel frac spreads and light-duty trucks. Last year, half of its contracted rig fleet was running on gas, said EnCana spokesman Doug McIntyre. “The cost savings we see from using natural gas, to power our drilling rigs, ranges from about $250,000 per year for an LNG/diesel dual-fuel rig, and up to $1.75 million per year for a dry field gas dedicated rig,” he said. “In addition to strategic cost savings, this effort also adds to the environmental performance of our operations, since powering vehicles with natural gas reduces the harmful environmental and health impacts associated with exhaust from diesel-powered vehicles.”
EnCana began the transition to gas rigs in the Horn River basin of British Columbia and, more recently, initiated a pilot project in Colorado’s Piceance basin that is testing LNG-fueled pumps. “The high-horsepower application required a large amount of diesel fuel, which provided a tremendous opportunity for displacement with natural gas. As a baseline, we experience displacement of approximately 2,000 gal of diesel fuel per day, at a cost savings of about $2,800 per day,” said McIntyre.
TIGHTER SPACING IN SIGHT
With many of the more developed shale plays now in full-scale development mode, the already close proximity between pad wells continues to tighten, as operators devote more time to evaluating optimum spacing. In the Eagle Ford, Bakken, Marcellus and elsewhere, a number of operators are conducting down-spacing studies, in an attempt to land more wells in tighter spacing schemes, while avoiding any communication between existing wellbores.
Whether increasing drilling densities on a multi-well pad ultimately drains more reservoir, and maximizes the economic value of a shale asset, remains open for debate. However, for the time being, operators seem convinced that determining the optimum well spacing within a play will pay off handsomely.
The Eagle Ford, particularly its liquids-rich windows, has been the field lab for much of the down-spacing studies conducted to date, though operators recently began examining tighter well spacing in the Bakken, Marcellus and other unconventional plays. Tim Dove, president and CEO of Pioneer Natural Resources, said the operator is encouraged by early results of tests in the Upper Eagle Ford, where well spacing was cut in half, from 1,000 to 500 ft. “Recently, we have been doing further down-spacing, to about 300 ft, and the wells at 300-ft down-spacing seem to be performing in line with those of the 500 ft, and that’s extremely encouraging. We’re actually looking now, and drilling to test that space even further, to 175-ft spacing and these areas will, in some cases, include both lower and upper Eagle Ford wells,” said Dove during the fourth-quarter earnings call.
Marathon and EOG Resources, likewise, are among an escalating number of operators testing the feasibility of increased drilling density in the Eagle Ford, with the former looking at well performance on 40- and 60-acre spacing, primarily in its high gas-oil-ratio (GOR) and condensate windows. Marathon said its ongoing quest to determine optimal development spacing includes analyzing subsurface, petrochemical and performance data.
In North Dakota, Bakken pioneer Continental Resources Inc., which, at year-end, had increased its proven reserves in the play 38%, to 1.08 billion boe, said it had successfully completed the first of four planned, pilot density projects, Fig. 4. According to Continental, the down-spacing study at the Hawkinson Unit resulted in a combined, 14-well IP of 14,850 boed from the Middle Bakken, and the three benches of the underlying Three Forks (TF) shale. The first test was completed a month early, in October, the operator said.
The Hawkinson density project included four Middle Bakken, three TF bench One, four TF bench Two and three TF bench Three wells, all spaced 1,320 ft apart in the same zone, and offset 660 ft in the adjacent zones. Continental said the test represented the first density drilling program in the Bakken to include all the lower benches.
“The Hawkinson project is a milestone event and further validates our vision for full field development of the Bakken–Three Forks reservoirs in this world-class oil field,” said Continental President and CEO W. F. “Rick” Bott in announcing the test results. “Clearly, there is more oil to be recovered than previously perceived, and projects like the Hawkinson are leading the way to defining the optimum drilling density and pattern to maximize oil recovery. The news in the Bakken just keeps getting better.”
In the predominately gassy Marcellus shale, Cabot Oil & Gas said that results of a down-spacing pilot program on its first 10-well pad in Pennsylvania are promising. On the multi-well pad, Cabot reduced lateral spacing from 1,000 ft to 500 ft, between three Lower Marcellus wells, completed with a total of 62 frac stages, with an IP rate of 62 MMcfgd and a 30-day production rate of 56 MMcfgd. “While more production data and testing are needed to determine the optimal spacing of laterals across the play, the results from this pilot program reinforce our belief that tighter down-spacing will increase recoverable resource across our position, further enhancing the value of our Marcellus asset,” said Cabot Chairman, President and CEO Dan Dinges.
TUBULARS FEEL THE STRESS
Along with the new-generation drilling rigs, the widely promoted RSS and geosteering technologies developed by Schlumberger, Halliburton, Baker Hughes, Weatherford and others have played key roles in allowing operators to drill longer-reach wells, at considerably faster penetration rates and within ever-narrowing well paths. However, the downside of drilling of longer laterals at historically high rates of penetration (ROP), and often through increasingly severe doglegs, comes in the form of tremendous strains on downhole tubulars.
For one thing, increasing lateral distances magnifies torsional drillstring stresses that can accelerate thread connection failures. Last year, the Vallourec Group and NOV Grant Prideco led the industry in designing advanced, double-shoulder rotary connections, capable of withstanding the higher torque values. Vallourec claims its VAM Express double-shoulder connection delivers up to twice the average torque capacity of standard API connections, while Grant Prideco said its eXtreme Torque (XT) double-shouldered rotary connections provide more than 25% higher torsional capacity, without increasing fatigue risks.
Further compounding the stress on OCTG used in unconventional drilling is the widespread use of mud motors, which are driven by pressure from the mud pumps. Consequently, the bit attached to the motor rotates, while the drill pipe remains stationary, thereby creating severely uneven wear of the hardbanding applied on the OD to extend the life cycle of downhole tubulars. A leading developer of specially engineered hardbanding, NOV Tuboscope, says the use of mud motors poses particular difficulties in applying a hardband. Tuboscope augmented its pacesetting TCS-8000 line of casingfriendly hardbands with the TCS-Titanium product, which, it says, offers an optimum combination of casing wear protection and tool joint durability.
“The utilization of high-RPM mud motors used in shale drilling has created new challenges on drilling tools, as well as the hardband on these tools,” says NOV Tuboscope Hardbanding Product Line Manager Mark Juckett. “When the drill stem is rotating, the hardbanding is typically worn uniformly, but, when drillstem rotation stops in most steering applications, the drill stem can be worn eccentric, creating flat areas of the hardband and/or tool joint. To repair this pipe, we then will apply hardband to the flat area, and feather the weld into the existing high side.”
“Along with record rates of penetration, these challenges have compelled us to review and edit our SOPs (standard operating procedures) for this type of application,” added Juckett.
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