The Age of Superlaterals: Multi-Well Pads, Walking Rigs, High-Speed and Rotary Steerable Drilling, Zipper 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 Oil & Gas Per Well, Per Pad, Per Frac Stage, and Per Amount of Land Disturbed

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.  

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. 

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.

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.

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