The Age of the Superlaterals: Multi-Well Pads, Walking Rigs, High-Speed
and Rotary Steerable Drilling, Pad Fracking, Better Targeting and Target
Maintenance, Synthetic Oil-Based Mud, and Tightly-Spaced Frac Stages with More
Proppant Per Stage: Oil & Gas Drilling and Completion Innovations That
Recover More Gas & Oil Per Well, Per Pad, Per Frac Stage, and Per Amount of
Land Disturbed
Improvements in well drilling and well completions have
resulted in very significant efficiency gains over the last several years in
unconventional drilling. This is typically the horizontal drilling and fracking
in mostly U.S. shale plays that dominates new gas and oil production in the
U.S. With the recent downturn in oil and gas from late 2014 through 2016 the
need for cost-reduction was very strong. Now that oil, NGL, and natural gas
prices have recovered and the industry along with them, the innovations are
here to stay and continue to improve incrementally.
One way of measuring efficiency improvements used by the
Energy Information Administration is what they call Drilling Productivity. This
is measured in average gas and/or oil production per rig employed. Appalachian
natural gas production per rig has increased 10-fold over the last 8 years. From
the latest drilling productivity report for Appalachia it can be seen that
production per rig quadrupled from Sept. 2012 to August 2016 as some of these
improvements came to fruition. The increase has been fairly uniform overall but
doubled from April 2015 to August 2016 and then
dropped slightly due to the industry downturn before resuming increases.
Other ways of comparing well results include EUR (estimated
ultimate recoverable production) per 1000 ft of lateral and production per frac
stage. For new areas where little or no production is available there is IP
(initial potential, or estimated rate) per frac stage. These numbers have been
extensively used in company investor and analyst presentations. While pre-horizontal drilling used to be tabulated in cost per foot (CPF) it is now tabulated in cost per lateral foot (CPLF). Range Resources' Drilling VP Don Robinson notes that Range's CPLF has come down consistently over the last several years with longer laterals drilled faster with less down-time and costly accidents:
Superlaterals: In Appalachia and Elsewhere
Eclipse Resources has been the pioneer in superlaterals in
the Utica-Point Pleasant Shale play in eastern Ohio. They have now drilled
quite a few of these long laterals, although they do acknowledge that there
will be a limit to how long laterals can go. EQT has also begun drilling long
laterals of 15,000 ft or more in the Marcellus and Upper Devonian Burket in
Pennsylvania. They plan to drill much of their laterals at these lengths where
applicable. At the recent DUG East meeting there was a panel that discussed
completions and long laterals. They touted the economic advantages of long
laterals but also acknowledged that there were risks – typically drilling and
casing issues. Eclipse VP of drilling and completions Oleg Tolmachev also gave
a rundown at DUG East of their superlaterals. He noted that they now have 15
superlaterals with an average lateral length over 18,000 ft with the longest,
the Purple Hayes, at 20,803 feet of lateral. The lateral part of the well was
drilled in 13 days.
“We spread our fixed costs for things such as roads,
vertical wellbore, pad size and surface facilities across the footage of the
lateral,” Tolmachev said.
Also noted in the E&P article referenced below is the following:
“In the lateral section the proper rotary steering tool must
be used to minimize horizontal doglegs. Mud rheology can improve the wellbore
stability as well as the use of managed pressure drilling. In addition, the
proper mud will also manage gas influx and prepare the well for “frac hits” and
production interference.”
“To manage circulation, three mud pumps are suggested for
the best circulation rates at total depth and split-string drill pipe is also
used to maximize circulating rates and minimize friction losses.”
In mid-2017, Chesapeake announced completing a 17,000 ft
lateral in the Eagle Ford Shale, the longest in that play. In 2018, Range Resources drilled two 18,000 ft laterals in the Pennsylvania Marcellus, the longest wells in the play thus far. Ascent Resources' longest lateral so far in the Utica is 16,500 ft. with plans to drill several laterals longer than 15,000 ft. Antero Resources drilled four wells with lateral lengths of 17,400 ft.
The record for the longest on-shore lateral now belongs to
Conoco Phillips with their 21,478 ft lateral in Alaska’s North Slope, announced
in April of this year.
There are limits to how long a lateral can go and they vary
by formation, or rather by how deep the vertical section of the well is. This
is due to the ability to drill and get casing to bottom, to deal with
ever-increasing friction in longer and longer wells. I am guessing that circulating drilling mud and minimizing mud loss is challenging with 4 mile laterals which in the Utica make the entire measured depth closer to 6 miles - even with 3 mud pumps. Circulating cement might be challenging as well.
Drilling Innovations
There are advances on both the well-drilling and well-completion
side that have contributed to the efficiency gains. On the drilling side are the
advantages of rotary-steerable drilling systems, better geo-targeting and
target maintenance through geosteering, better mud systems such as synthetic
oil-based mud that offers very good well-bore integrity, better mud pumping
criteria, better solids control strategies, better bits, and better borehole
management techniques. ‘Better’ for one formation or play may not be the same for
another as many of the drilling tweaks are play-specific. Each play goes
through a series of learning curves that lead toward ‘optimization,’ which usually
refers to the highest efficiency of any technology. Walking rigs are another innovation.
These drilling rigs can move from one borehole on a pad to another – typically about
20 ft away – very quickly to minimize time between wells. Multi-well pads have
been the norm for several years now and now super-pads are being built targeting
multiple formations. Targeting multiple formations allows the laterals to be spaced
closer together. This does, however, require better and more frequent ‘anti-collision’
analysis. Super-pads may also be more of a nuisance for anyone living nearby so
where they are put needs to be considered. Another drilling innovation has been
to begin curve-building at much higher depths, allowing for smaller borehole
kinks, ie. ‘doglegs,’ and better management of multiple wells on a single pad. Wells
may be 2D, curving in one direction only, or 3D, swinging out to avoid other
wells on the pad and to achieve desired spacing between laterals, and they may
swing behind for a while, adding length to wells where length is constrained by
acreage boundaries.
Robinson, in the Journal of Petroleum Technology article referenced below also note that longer laterals require rig adaptations such as mud pumps rated for 7500psi rather than 5000psi, 2000hp pumps rather than 1600hp pumps. The added pressure is required to clean the hole and helps power the rotary steerable tools. Stronger top drives, more rack back capacity for drill pipe, and additional power generation are other rig adaptations. Better monitoring of mud properties and shapes and sizes of drill cuttings are also helping drilling adapt to longer wells.
Robinson, in the Journal of Petroleum Technology article referenced below also note that longer laterals require rig adaptations such as mud pumps rated for 7500psi rather than 5000psi, 2000hp pumps rather than 1600hp pumps. The added pressure is required to clean the hole and helps power the rotary steerable tools. Stronger top drives, more rack back capacity for drill pipe, and additional power generation are other rig adaptations. Better monitoring of mud properties and shapes and sizes of drill cuttings are also helping drilling adapt to longer wells.
Multi-Well Pads and Super-Pads
Multi-well pads are now industry-standard. They lower costs in
a number of ways. Some are: less entrance roads, more accommodating for frac-water
delivery pipelines and frac-flowback water pipelines, sharing of some production
equipment, easier to tie-in multiple wells in the same time frame, evaluating data
on a per pad basis, less time and money spent in rig and equipment moves,
ability to frac wells in sequence – zipper frac, and ability to drill and set
conductor casing very efficiently.
EQT has recently permitted and begun work on a 40-well pad
targeting wells in the Ordovician Utica-Point Pleasant, the Middle Devonian
Marcellus, and the Upper Devonian Burket/Geneseo. However, they note that they
may not drill all the wells on these superpads. So far, the most wells they
have drilled from a single pad is 22 (at least as of Jan. 2018). They are
averaging 17 or 18 wells per pad in addition to drilling long laterals of
15,000 now routinely. In the Permian Basin of West Texas, Encana has built a
pad for 64 wells!
EQT has been drilling 5 or 6 wells on a superpad, then
completing them and producing them for a while till their high flush production
declines a bit before going back to drill the next set. This is done so that
pipeline size can be optimized for each packet of wells rather than being undersized
for flush production then oversized as gas production declines. Range Resources
noted that they were building pads to accommodate 20 wells and that they could return
to drill the next set of wells when ready or wait until gas prices or NGL
prices are adequate if necessary – so it options them for quick reaction to
market forces. An example below shows an EQT pad with 22 wells.
Rotary Steerable Directional Drilling Systems
Rotary Steerable Drilling Systems offer some advantages over
traditional mud motors, including faster drilling and lower dogleg severities.
The lower doglegs are important for longer laterals, likely essential for
superlaterals, since getting casing to the toe-end of the laterals can be an
issue. Too many, too big, and too tightly-spaced doglegs can also negatively
affect drilling. Another advantage of rotary steerable systems is that their
survey tools that measure orientation and gamma ray probes of the rocks are
closer to the bit so that steering decisions can be closer to real-time than in
conventional ‘bottom-hole assemblies’ where they are farther back on the drill
string. This is especially advantageous in areas where rocks are highly folded.
However, conventional mud motors may be quite adequate and more economic in
several areas with less geological variation and in shorter laterals.
High-speed drilling in general has been allowed by better drill-bits, better mud system management, better directional drilling, and better geosteering. Several rigs have entered or frequent the "mile-a-day" club. Appalachian Basin driller Antero Resources notes they drilled a record 8206 ft in 24 hours and their avg. footage drilled in a day ticked up to 4700ft. The overall trend is toward faster drilling or at least reasonably fast drilling. There can be dangers when drilling too fast as the mud system and pump volumes and rates need to be adequate to clean the hole and the jets jetting fluid from the bits need to be adequate to clean the bit. MWD sampling rates have to be frequent enough to get a detailed gamma ray log.
High-speed drilling in general has been allowed by better drill-bits, better mud system management, better directional drilling, and better geosteering. Several rigs have entered or frequent the "mile-a-day" club. Appalachian Basin driller Antero Resources notes they drilled a record 8206 ft in 24 hours and their avg. footage drilled in a day ticked up to 4700ft. The overall trend is toward faster drilling or at least reasonably fast drilling. There can be dangers when drilling too fast as the mud system and pump volumes and rates need to be adequate to clean the hole and the jets jetting fluid from the bits need to be adequate to clean the bit. MWD sampling rates have to be frequent enough to get a detailed gamma ray log.
Targeting and Geosteering Strategies
Geosteering has played a role in increasing drilling
productivity. The first step is finding the best zone to drill laterally in
each play. This may involve geochemistry, gas-in-place analyses, TOC analysis,
geomechanics, avoiding zones with high clay content, or favoring zones with
higher silica content or a certain type of carbonate content. Typically, the
silica-rich and sometimes carbonate-rich zones are more brittle and frac-able
while the clay-rich zones are less brittle, more ductile, and so have less
frac-ability. Once the preferred zones are determined and tested through
drilling and production then the goal is to stay in or very near those zones in
rocks that may be subject to folding, faulting, depositional thinning, and
other facies variations. Being in these best zones often means more of the
preferred rock in terms of both gas content and the ability to initiate
fractures is accessed via the borehole. This has been termed ‘primary reservoir
access.’ Production data have shown that “geosteering efficiency,” or the
ability to stay in zone does indeed correlate to better production. That means
that increasing geosteering efficiency, or primary reservoir access, even by a
few percentage points can have a significant effect on production and
profitability. In faulted and highly folded areas, most geologists and
engineers think that the tectonics negatively affect production mainly by
causing the induced hydraulic fractures to propagate into the existing faulted
and naturally fractured rock rather than cracking the rock anew in a more
consistent and far-reaching manner. This is still an open question as some
still like naturally-fractured areas but all agree that large faults are to be
avoided – additionally since staying in zone in those areas is often difficult
or impossible. Successful geosteering requires coordination between
geosteerers, drilling engineers, and directional drillers. It requires vigilant
data interpretation in real-time in a dynamic system – rock dip orientation
variability. It also requires the ability to know how drilling and surveying
can affect the data. It involves frequent qualitative decisions based on mostly
quantitative data interpretation and eliminating competing interpretations.
With effective geosteering it is possible to optimize primary reservoir access by
placing and maintaining the wellbore in small target intervals.
Completion Innovations
On the completion side there is possibly the largest effect
on well-production – proppant loading. This is simply how much proppant can be
pumped into the induced fractures during hydraulic fracturing operations.
Proppant is typically sand of specific and uniform sizes that is pumped in
order to hold open the induced hydraulic fractures. Studies have indicated that
proppant placed per frac stage probably has the most positive effect on
production per cost. Different companies have different sand recipes and
pumping schedules for each frac stage that they tweak. More closely-spaced frac
stages has also lead to very significant well-production increases. Frac stage
spacing is probably now optimized as much as it will be due to diminishing
returns on closer and closer spacing. Ascent Resources notes that they use 150ft stage spacing in their gas wells and sometimes closer for liquids. They proppant load at 1500-3000 lbs per foot. They also mention spacing perf clusters 30-35 ft apart. Antero Resources notes their average proppant loading at 2000 lbs per foot. Well results are getting bigger with flush production and pressure lasting longer. 2-2.5 BCFeq/1000ft of lateral is the EUR range in the core areas of Marcellus and Utica with some even exceeding 2.5 BCFeq/1000ft of lateral.
The biggest gains in EIA’s drilling productivity graph have likely come from closer spacing and more proppant loading between April 2015 to August 2016 when the wells with closer stage spacing and more proppant per stage first came on-line en masse. Another completion-side innovation has been pad fracking where wells on a pad are hydraulically fractured in sequence. So-called ‘zipper fracturing’ has been the most adopted technique. Diversion, or diverting frac fluids to perforation clusters, is also being evaluated. This would allow more specific proppant placement and in theory could get as much stimulation over more rock – according to the DUG East discussion– making say a 300 ft stage spacing as effective as a 150 ft stage spacing, which could save significant completion costs while stimulating an equivalent amount of rock – in theory, as these techniques are still being evaluated.
Zipper fracturing allows pad wells to be fracked simultaneously so that while one process is going on in one well another may be going on in another well, thus optimizing efficiencies. Fracs can be monitored and 'mapped' with microseismic and fiber optics to determined where the energy of each stage went in 3D space.
The biggest gains in EIA’s drilling productivity graph have likely come from closer spacing and more proppant loading between April 2015 to August 2016 when the wells with closer stage spacing and more proppant per stage first came on-line en masse. Another completion-side innovation has been pad fracking where wells on a pad are hydraulically fractured in sequence. So-called ‘zipper fracturing’ has been the most adopted technique. Diversion, or diverting frac fluids to perforation clusters, is also being evaluated. This would allow more specific proppant placement and in theory could get as much stimulation over more rock – according to the DUG East discussion– making say a 300 ft stage spacing as effective as a 150 ft stage spacing, which could save significant completion costs while stimulating an equivalent amount of rock – in theory, as these techniques are still being evaluated.
Zipper fracturing allows pad wells to be fracked simultaneously so that while one process is going on in one well another may be going on in another well, thus optimizing efficiencies. Fracs can be monitored and 'mapped' with microseismic and fiber optics to determined where the energy of each stage went in 3D space.
Also discussed at DUG East were “frac hits” where
hydraulically fracturing a “child well” (basically an infill well) causes
changes in pressures and production in a “parent well” (basically a
pre-existing legacy well). It has also been called “frac-bashing!” Sometimes a
child well may stimulate a parent well and sometimes (probably more often) it
may make it perform worse. It is likely that each play is different in this
regard. “Pressure rejuvenation of parent wells” may become a more applicable
technology as it develops. The jury is still out on the economics of “re-fracking”
old wells that used less effective stimulation techniques, but certain candidates
are probably ideal for it. Other techniques being explored include the use of highly
durable ceramic proppant which is more expensive but may be worth it for certain
plays with high reservoir temperatures and pressures.
More proppant per frac stage also means more frac sand, a lot more. E & P Magazine, in an article referenced below shows how efficiently getting the large mount of frac sand to well pad locations for simultaneously fracking multiple wells through zipper fracking can save money and time (time is money on completion jobs as any time lost waiting can be very expensive). Again, the goal is optimization.
More proppant per frac stage also means more frac sand, a lot more. E & P Magazine, in an article referenced below shows how efficiently getting the large mount of frac sand to well pad locations for simultaneously fracking multiple wells through zipper fracking can save money and time (time is money on completion jobs as any time lost waiting can be very expensive). Again, the goal is optimization.
References:
Superlaterals: Going Really, Really Long in Appalachia – by Larry Prado
(ed.), in Hart Energy E&P Magazine, July 2, 2018
Chesapeake, Laurel Mountain, BHGE Discuss Completions in Appalachia –
by Velda Addison (Ed.), in E&P Magazine, July 10, 2018
ConocoPhillips claims North American record for horizontal drilling –
by Alex DeMarban, in Anchorage Daily
News, April 23, 2018
These days, oil and gas companies are super-sizing their well pads – by
Anya Litvak, in Pittsburgh Post-Gazette, Jan. 15, 2018
Shale Oil: The Arrival Of Super-Laterals Is Just A Matter Of Time – by Richard
Zeits, in Seeking Alpha, June 30, 2017
Drilling for Miles in the Marcellus: Laterals Reach New Length - by Range Resources (Don Robinson VP of Drilling), in Journal of Petroleum Technology, Aug. 8, 2018
Efficiency Gains Help Independents Find Success in Marcellus, Utica Shale - by Al Pickett, in American Oil & Gas Reporter, August 2018
Optimizing Frack Sand's Last Mile - by Zach Carusona, Sand Box Logistics, in Hart's E & P Magazine, Aug. 15, 2018
Drilling for Miles in the Marcellus: Laterals Reach New Length - by Range Resources (Don Robinson VP of Drilling), in Journal of Petroleum Technology, Aug. 8, 2018
Efficiency Gains Help Independents Find Success in Marcellus, Utica Shale - by Al Pickett, in American Oil & Gas Reporter, August 2018
Optimizing Frack Sand's Last Mile - by Zach Carusona, Sand Box Logistics, in Hart's E & P Magazine, Aug. 15, 2018
