ShaleTech: Permian Shales
The Permian basin may be to shale operators what timberlands were to hardscrabble investors during the Great Depression: A decent-yielding refuge in an otherwise bleak landscape.
Indeed, much like the logging-related investments that delivered rare growth in the gloomy 1930s, the high-flow shale reservoirs underlying most of West Texas and southeastern New Mexico continue to deliver respectable margins, at a time when breaking even generally can be considered an economic triumph. As reflected in tidy stock offerings of late, Permian-centric producers also enjoy a comparative equity advantage, with investors attracted by the combination of multiple, stacked pay zones, excess oil takeaway capacity and what one operator categorized as “exceptionally low well costs.”
“The Permian basin is where you tend to get the best bang for your buck,” Saira Malik, head of global equity portfolio management at TIAA-CREF Asset Management, told the Wall Street Journal on Dec. 9. So much so that the greater Permian Basin Petroleum System, comprising the greybeard Midland, the more emerging Delaware and the Northwest Shelf subsets (Fig. 1), is siphoning resources from Texas’ other signature unconventional play, the Eagle Ford. Pioneer Natural Resources, for one, laid down the six rigs it was running in South Texas at year-end, and will divert 90% of its $1.85-billion drilling and completions budget to its western acreage. “It’s a nice trade to be able to take monies out of Eagle Ford, where the economics are not very good today, and put them in an area that’s outperforming,” says CEO Scott Sheffield.
However, delivering more bang for the buck is relative, when juxtaposed with doggedly low commodity prices, forcing most operators to respond in kind by furloughing rigs and personnel, and scuttling assets considered even remotely outside their core. Disparate strategies range from exploiting low drilling costs to build up drilled-but-uncompleted (DUC) inventories (the estimates of Permian DUC wells vary widely), to high-intensity completions and remote surveillance technology aimed at squeezing out more production now. Others, like Apache, believe the most prudent strategy is to drill fewer wells in the first place.
“As we look ahead to 2016, our Permian rig count will fall from 10 at the beginning of January to four by mid-year. Permian well completions are expected to be down 75% year-over-year,” says Apache President and CEO John J. Christmann. “These actions clearly demonstrate that we are willing to let our Permian production decline, until we are in a better investment environment.”
This, despite what he terms “exceptionally low” total well costs, ranging from $4.5 million for typical Delaware basin Bone Spring and Wolfcamp wells to horizontal Yeso wells on the Northwest Shelf that are trending below $2.3 million/well. “In terms of our Permian well cost, we see things coming down even further this year,” said Christmann. Driven largely by the Bone Spring formation, Apache delivered record quarterly production of 174,000 boed to close out 2015.
KEY METRICS DOWN
Early in 2016, it appears that operators are only willing to throttle back slightly on what had been routine yearly production records. The latest data available from the Texas Railroad Commission (TRC), the state’s chief regulator, shows oil production of 1,300,092 bpd as of January, compared to a 2015 average of 1,383,817 bpd. Gas production dropped a bit more sharply to 4.433 Bcfd from the 4.823 Bcfd documented last year. In the New Mexico Delaware basin fairways of Eddy and Lea counties, operators produced an aggregate 19,593,796 bbl of oil in the first two full reporting months of 2016, compared to 20,153,127 bbl for the like period of 2015, according to data from the New Mexico Oil Conservation Division (OCD). According to the OCD, gas spiked in January and February 2016 to 95,834,843 Mcf, compared to 78,560,810 Mcf in the same two months last year.
While a late-December blizzard is blamed for shutting in a significant amount of production early in the year, the U.S. Energy Information Administration (EIA) expects the downward, albeit modest, trend to continue throughout the two-state basin, at least through May, Fig. 2.
No such ambiguity exists on the drilling side, where the rig count has been dropping steadily, and new permits are on pace for a significant drop-off over 2015. According to the most recent Baker Hughes tally, 141 rigs were active in the Permian as of April 17, down one week-over-week, but an improvement over the week of April 8, when three rigs were idled. At the same time last year, 258 rigs were reported active across the 75,000-mi2 play.
If the first quarter is indicative of an ongoing trend, new wells will be down appreciably in 2016. Between January and April 14, 813 horizontal drilling permits were approved for the three Permian-specific TRC districts (8, 8A and 7C), compared to 1,021 similar authorizations in first-quarter 2015.
SELLER’S MARKET
Despite the murky market, entry costs remain high. “Given the capital chasing acreage in the Permian, property values remain high, but our acquisition efforts in 2015 were disciplined, targeted and privately negotiated,” says Tim Leach, chairman, CEO and president of Concho Resources.
Leach was referring to Concho’s three-pronged asset shuffle, which closed in January and included the $360-million acquisition of 12,000 net acres in Texas’ Reeves and Ward counties, adjacent to its North Harpoon prospect in the southern Delaware basin, and the sale of 14,000 net acres in Loving County, Texas, for $290 million. Concho also finalized an asset swap with Midland, Texas, institution, Clayton Williams Energy.
Concho, which holds approximately 1.1 million gross acres, plans to cut its operated rig fleet from 18 at year-end 2015 to 11 active rigs this year, as it continues to tweak well designs with, on average, 35% longer laterals (from 5,200 ft in 2015 to more than 7,000 ft).
Meanwhile, pure-play Parsley Energy and RSP Permian, both based in Midland, added a cumulative 24,158 net undeveloped acres to their respective portfolios, following multi-million-share stock offerings.
Parsley was expected to close in May on its aggregate $359-million acquisition of 22,908 undeveloped acres in the southern Delaware and Midland basins. The purchase, which will increase Parsley’s Permian leasehold to 115,586 net acres, comes on the heels of April’s upsized common stock offering of more than 18.2 million shares that was expected to net $390.6 million.
The company reported full-year 2015 production of 22,000 boed, up 55% from the year prior, and projects a 35–50% increase this year. Parsley operated four rigs throughout the fourth quarter, drilling 15 wells and completing 18, and expects to complete 60–70 horizontal wells this year.
Upon finalizing its $137-million acquisition of roughly 1,250 net, undeveloped acres and 115 boed of production from Wolfberry Partners in November, RSP holds 64,000 acres in the Midland basin. Prior to closing, RSP had completed an offering of 8.7 million shares of common stock for net proceeds of $218.1 million.
RSP plans to operate two rigs for the remainder of 2016. During 2015, RSP drilled 10 horizontal wells and completed eight as operator, while participating in the drilling and completion of another 15 and eight horizontal wells, respectively. RSP closed out the year with an operated, 18-well DUC inventory, with 13 non-operated wells awaiting completion.
With a primary focus on its 585,000 net acres in the New Mexico quadrant of the Delaware basin, Devon Energy is fielding offers for 15,000 undeveloped acres in Martin County, Texas, and producing Wolfcamp assets in the southern Midland basin. The Midland basin is among the non-core acreage that Devon plans to divest in four U.S. onshore plays.
Devon closed 2015 with five active rigs, compared to 10 rigs at the end of the third quarter. Devon put 14 Bone Spring wells online in the fourth quarter, which saw production rise 45%, year-over-year, to 66,000 boed.
SHORT-CYCLE PIVOT
As it wraps up committed expenditures for LNG trains and similarly long-cycle projects, Chevron says its more than 2-million-acre legacy leasehold in the Permian basin will occupy a higher tier in its asset portfolio. The super-major says it intends to shift more capital toward its shale holdings to take advantage of shorter-cycle returns.
“First among these opportunities is the Permian, where we have a large royalty advantage acreage position, and our view of the resource potential continues to increase,” James Johnson, executive V.P., upstream, told security analysts on March 8. “Our transition to a horizontal factory mode is now fully operational, with the utilization of four-well pads and increasing lateral lengths.”
“You will see more spending in the Permian, and as we continue to make progress in other shales, I think you will see growth as well. By the middle of the next decade, 20% to 25% of our production could be in the short-cycle shale and tight activity,” said Johnson, Fig. 3.
Chevron plans to run seven operated and nine non-operated rigs, drilling an estimated 175 wells. In 2015, Chevron drilled 147 net wells and participated in 180 non-operated wells.
In addition to its net leasehold, Chevron also participates in a Delaware basin joint development agreement (JDA) with Cimarex Energy that covers 100,000 acres in Culbertson County, Texas, where the Denver independent expects first production in May from its ongoing, upper Wolfcamp downspacing pilot. The six-well, 7,500-ft lateral pilot, drilled in a staggered pattern, is testing two spacing designs, featuring eight and six wells/section.
Cimarex’s fourth-quarter production was down 8% from the previous quarter, averaging 520 MMcfed. From all indications, 2016 will be another year of downsizing, as it entered the period with six operated rigs, but by June plans to be down to two in its 230,000 net acres. Cimarex drilled 60 net Wolfcamp and Bone Spring wells in 2015, compared to 117 the year prior.
“We think the best activity level for Cimarex in 2016 is preservation mode,” says CEO Tom Jorden.
TOP TIER ASSET
Flush off reaching its 2016 Permian production growth target a year early, Occidental Petroleum is funneling most of its remaining E&P-directed capital into its commanding 5-million-acre leasehold. Oxy, which finalized the sale of its Bakken shale assets on Nov. 20, closed out 2015 with Permian production up 47% (35,000 boed), year-over-year. “Permian resources growth exceeded our expectations, as we reached our 2016 growth target of 120,000 boed. This was a year ahead of our original plan,” said CEO Vicki Hollub, adding that production is expected to average 123,000 boed through the first half of the year. Oxy plans to run between two to four rigs this year.
As with many of its peers, Occidental’s modus operandi for maximizing reservoir drainage centers on longer laterals with higher-density completions and proppant loads, the results of which are reflected in “solid well performance,” says Domestic Oil and Gas President Jody Elliott. To illustrate, he points to the 19 Delaware basin Wolfcamp A wells put online in the fourth quarter, one of which achieved a peak flowrate of 1,659 boed, only to be surpassed by a Midland basin well that delivered a peak rate of 2,167 boed from the Wolfcamp A bench. However, one Delaware Bone Spring well, hooked up in the fourth quarter, overshadowed those two with peak production of 2,498 boed.
Elsewhere, following the April closing of the $910-million divesture of its Wyoming Piceance basin operations, Oklahoma’s WPX Energy plans to go all-in developing the 92,000 net acres that it acquired last year for $2.35 billion. WPX plans to run two to three rigs this year, as it systematically evaluates its leasehold. “In the Delaware basin, we’re already seeing EURs that are 25% above our acquisition assumptions,” says President and CEO Richard E. Muncrief.
‘OPTIMIZED’ COMPLETIONS
Pioneer says it has no intention of leaving wells uncompleted this year, as it continues to test optimized completions across its 825,000-acre leasehold in the Midland basin. The company plans to run eight completion crews, at least through the first half of 2016, including two transferred from the Eagle Ford. Pioneer projects to exit 2016 with a 10% year-over-year increase in production from 204,000 boed to 224,000 boed.
“We’re just going to be continuously completing the wells there with our fleets. And so you will not see any (DUC) in the Midland basin,” says President and CEO Tim Dove. “Despite the fact we’ve had weak commodity prices, we are still generating good returns on the wells we’re drilling.”
That said, Pioneer plans to reduce its horizontal rig count from 18 at year-end 2015 to 12 active rigs in its northern Sprayberry/Wolfcamp acreage. By mid-year, it plans to idle the four rigs presently drilling in the southern acreage as part of the JV with China’s Sinochem. Nevertheless, the company plans to drill 195 wells and connect 230 wells to production this year, compared to the 197 new producing wells delivered in 2015. Dove said building a DUC inventory would negate ongoing efforts to evaluate new completion strategies for its average 9,000-ft laterals, which include reducing stage lengths from 240 ft to 150 ft, while increasing per-stage frac clusters from four to five, with higher fluid volumes and sand concentrations.
Encana, likewise, shows no inclination of building a DUC inventory, with four completion crews working simultaneously on its 14-well RAB Davidson 27 pad targeting the Wolfcamp in Midland County, a spokesman said in late April. Encana was operating four rigs (Fig. 4) in its 146,000-net leasehold in the first quarter, including one dedicated to conventional wellbores.
President and CEO Douglas James Suttles told analysts that more than half of Encana’s 2016 capital budget, which is down 55% year-over-year, will be allocated to the Permian basin. The Canadian operator plans to drill 45-50 horizontal and 20-25 vertical wells this year. Production guidance for 2016 has not been made available.
As of now, EOG Resources also plans to run four rigs in its combo 372,000-net-acre Delaware basin properties, where it targets the Wolfcamp, the second bench of the Bone Spring and the Leonard shales. The Houston independent plans to complete 75 net wells in the Delaware basin this year, one more than the total completed in 2015.
NEW LOOK AT PRODUCTION
BHP Billiton, meanwhile, is combining remote well surveillance technology with a change in operating philosophy to maximize revenue from existing Upper Wolfcamp producers within the 72,000-net-acres that it controls in Reeves County, Texas. The operator is currently running two rigs (Fig. 5) devoted strictly to hold-by-production (HBP) requirements. “The goal of our production optimization (initiative) is to get as much production as we can from existing wells while spending the least capital,” says Shola Adegoke, senior production engineer-Permian. Specifically, with multiple single-producers spread across its expansive Delaware basin leasehold, detailed daily monitoring of every well to ensure optimal production was a formidable proposition. Accordingly, BHP launched the internal initiative aimed at remotely addressing the logistical restrictions of relying on a pumper to physically check each meter daily to monitor key process conditions, which could leave wells shut-in or, at best, under-performing for extended periods, said Jacob Savoy, BHP facilities engineer.
“In addition to investment in EFM (electronic flow measurement) and automation, we have a suite of processes and surveillance tools in place to survey the field in a very granular level, and we are able, in real time, to remotely rank where we’re producing less than our ideal rate,” Savoy said. “We can actually prioritize from a remote location before we send pumpers to the field and have them deal only with the wells that aren’t producing at their (established) ideal rate.”
Savoy said simply lowering tubing head pressure from 230 psi to 150 psi, based on defined control points, has been shown to increase gas production 25% within 48 hr. According to Adegoke, the dual initiative to optimize production and cut costs has delivered on some wells an incremental production as high as of 400 Mcfgd and 100 bopd, while reducing controlled downtime 70%. 
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