Major US operators entered 2017 with increased capital budgets and plans to ramp up drilling in the Lower 48’s most promising regions, namely the Permian basin and Sooner Trend Anadarko basin Canadian and Kingfisher counties (STACK) play.

The rig count rebound that began in late spring 2016 continued into midyear 2017, gaining 554 units to a recent high of 958 rigs working during the week ended July 28, according to Baker Hughes data.

However, growth has slowed over the past couple of months, and prolonged oil market volatility has caused a midyear curtailment in exploration and production spending among several firms, with Anadarko Petroleum Corp., ConocoPhillips, and Hess Corp. first to report cuts and Marathon Oil Corp., Pioneer Natural Resources Co., Devon Energy Corp., and Continental Resources Inc. following suit in the subsequent weeks.

Some firms as a result are planning to run fewer rigs in the second half as equipment markets were already tightening before the recent drop in oil prices. Some are delaying completions for the time being. 

Despite more-conservative approaches moving forward, many firms are maintaining or even lifting their planned production levels for the year thanks to increased first-half activity and operational efficiencies including faster drilling from high-spec rigs, multiwell pads, and longer laterals along with continuously improving completions.

Permian operators including Chevron Corp., Apache Corp., Encana Corp., and RSP Permian Inc. have warmed to drilling multiwell pads as of late, research and consulting outfit Westwood Global Energy Group recently noted.

“Pad drilling offers numerous benefits, including reduced drilling cycle times and smaller surface footprints with the possibility for increased frac efficiencies and simultaneous operations,” Westwood explained.

“Other shale plays, including [the] Bakken, DJ-Niobrara, and Haynesville, are more mature in the adoption of pad drilling. For example, over 85% of the wells drilled Bakken and 90% of wells in DJ-Niobrara are on multiwell pads,” it said.

Because the first well drilled on a pad typically isn’t brought on stream until the last well is completed, however, more time than usual lapses between the drilling and production phases, resulting in more drilled-but-uncompleted (DUC) wells.

Data from the US Energy Information Administration indicate the Permian in June had 2,114 DUC wells, up 130 from the previous month and representing about a third of the overall DUCs from the seven major US onshore producing regions. About 15% of the Permian DUC backlog is from Anadarko, PNR, and Concho Resources Inc. based on the last 2 years of permitted wells, Westwood said.

As of the week ended Aug. 11, the Permian has added 243 rigs since its recent low in Baker Hughes data in May 2016, but growth there has slowed to just more than 1 rig/week over the past 2 months (OGJ Online, Aug. 11, 2017).

Big indies’ Permian bets

Marathon said it’s cutting its budget by $200-300 million to $2.1-2.2 billion after raising it in the spring amid its northern Delaware basin acreage acquisitions (OGJ Online, Mar. 21, 2017). The firm’s US operations nonetheless are expected to exit the year with both oil and oil-equivalent production up 23-27% from fourth-quarter 2016, an increase from its previous estimate of 20-25% growth. As planned, Marathon has 3 rigs working in the northern Delaware basin.

PNR trimmed its budget by $100 million to $2.7 billion, reflecting its decision to defer 30 Spraberry-Wolfcamp completions to 2018 “due to unforeseen drilling delays,” said Timothy L. Dove, PNR president and chief executive officer, in the firm’s earnings report.

“To maintain efficient operations, we have chosen not to accelerate activity in order to catch up in the second half, especially in light of the current commodity price environment,” he said.

PNR continues to operate 18 horizontal rigs in the Spraberry-Wolfcamp, of which 14 are in the northern area and 4 are in the northern portion of the southern Wolfcamp joint venture area. The firm now expects yearly production growth closer to the low end of its guidance range of 15-18% for 2017.

Concho is running 19 rigs in the Permian and expects to average 17 in the second half. It averaged 21 rigs in the second quarter. For the full year, the firm raised its production growth guidance to 24-26% and expects oil production to grow by more than 25%.

Concho also expanded further its Midland basin position on July 31 by acquiring 12,400 net acres with 100% working interest in Andrews and Martin counties, Tex., from an undisclosed seller for $600 million cash.

The properties include 3,000 boe/d of legacy production, of which 73% is oil. The acreage is contiguous with the Mabee Ranch leasehold Concho acquired from Reliance Energy Inc. in fourth-quarter 2016 (OGJ Online, Aug. 15, 2016).

In Apache’s much ballyhooed Alpine High prospect in the Delaware basin, meanwhile, the firm averaged 6 rigs during the second quarter and announced 2 parasequence well results in the oil window of the Wolfcamp, the first of which had a 4,500-ft lateral and recorded a 30-day average rate of more than 1,000 boe/d.

Apache noted that “early results from mapping and testing the zones give the company confidence, at a minimum, in hundreds of additional drilling locations, with a considerable amount of acreage and numerous landing zones still to be tested.”

Apache operated an average of 17 Permian rigs during the second quarter, with 8 overall in the Delaware as well as 6 in the Midland focused primarily on multiwell pad drilling in the Wolfcamp and Spraberry formations. The firm brought online the 9-well Schrock 34 pad in Glasscock County during the quarter.

Anadarko currently has 16 rigs drilling inthe Delaware basin and 6 in the DJ basin. Noble Energy Inc. is operating, as planned, 5 rigs in the Delaware basin and 2 in the DJ basin.

EOG Resources Inc. has revised upward its US crude production growth forecast for 2017 to 20% from 18%. In the Delaware, EOG intends to average 13 rigs working during the year while averaging 8 in the Eagle Ford and 2 in the Rockies.

Among the US supermajors operating in the Permian, ExxonMobil Corp. is running 16 rigs and Chevron Corp. is running 13.

Among international firms, BHP Billiton Ltd.’s current Permian rig will focus on near-term lease obligations while another 1-2 units will continue to focus on completion trials that will inform an eventual transition to full pad development.

Resilient pure-play Permian firms

Diamondback Energy Inc. has added a 9th operated Permian rig, which started work in the Midland basin. The firm plans to maintain 8-9 rigs working “in the current commodity price environment” while increasing its full-year production guidance by 5%.

Parsley Energy Inc. said it has taken delivery of all of rigs necessary for its 2017 drilling program because of “anticipated tightness in the market for high-specification drilling rigs.” It’s maintaining its planned capital spending while slightly raising its full-year net production guidance.

Consequently, Parsley spudded 49 gross horizontal wells in the second quarter while completing 27. The firm is reducing its expected completion count in the southern Delaware basin to reflect extended project cycle times earlier this year.

RSP Permian during the second quarter operated 4 horizontal rigs in the Midland basin and 2 horizontal rigs in the Delaware basin, where the firm added a third horizontal rig in May. RSP utilized 1 full-time completion crew during the second quarter in the Midland and a nearly full-time crew in the Delaware.

RSP drilled 22 operated horizontal wells and completed 18 operated horizontal wells. The firm began the quarter with 18 operated horizontal DUC wells and exited the quarter with a total of 22 operated horizontal DUCs. Its second-quarter production increased 106% year-over-year to 54,300 boe/d, of which 72% oil was and 88% liquids, and increased 20% quarter-over-quarter.

“Because of our strong well performance and operating efficiency, we have the capability to continue to grow our annual production volumes on a double-digit basis within cash flow at oil prices below $50/bbl," said Steve Gray, RSP Permian chief executive officer.

Other E&Ps still Permian focused 

WPX Energy Inc. is actually lifting its capital spending by around $85 million to $990 million-$1.07 billion while increasing its full-year oil production guidance by 8%. Incremental capital for the Delaware basin addresses the development of higher working interest wells, greater participation in nonoperated wells, inflationary pressure for oil field services, and additional funding for infrastructure, the firm said.

WPX currently is running 7 rigs in the Delaware, 2 in the Williston, and 1 in the San Juan basin.

SM Energy Co. has 7 horizontal rigs working in the Permian, with 2 in the Sweetie Peck area and 5 in the RockStar area. The firm recently converted the single vertical rig operating in the RockStar area to horizontal drilling and is currently running 3 completion crews. SM in the Eagle Ford is running 1 horizontal rig with plans to add a second during the third quarter.

Over the past year, the firm has collected 3,500 ft of core to better understand the entire Spraberry through Wolfcamp column, gather geomechanical rock properties necessary to support reservoir simulation efforts, and evaluate untested intervals. SM also just completed the first 10,000-ft laterals at Sweetie Peck and has just completed the first 6-well pad at RockStar that codevelops the Lower Spraberry and Wolfcamp A.

Pres. and Chief Executive Officer Jay Ottoson noted that SM has “generated more production than we expected with less capital investment than we planned" and therefore is increasing its 2017 production guidance by about 1 million boe/d.

Halcon Resources in the Delaware basin recently moved its 2 operated rigs from its Hackberry Draw area in Pecos County, Tex., to its Monument Draw area in Ward County, Tex., where they’ll be active for the rest of the year. The firm plans to add a third operated rig in the Delaware to resume drilling in Hackberry Draw in October.

The firm started completion operations with a dedicated frac crew in Hackberry Draw in late June and recently completed its first operated well, the Balbo Adrianna West 1H, which is currently flowing back after frac.

Halcon is currently fracing a 2-well pad there and expects the wells to be put online in mid-to-late August. The firm expects to put 7 gross wells online in 2017 in Hackberry Draw with an average working interest of 91%. It expects to spud a total of 11 wells in Hackberry Draw during the year.

The firm is drilling a vertical pilot well on the northern option acreage in Monument Draw and plans to drill a horizontal well in the Northern tract after reaching total depth on the pilot well. Halcon's dedicated frac crew will move over to Monument Draw later in the year. It expects to put 3 gross wells online in 2017 in Monument Draw.

Cimarex Energy Co. is operating 14 drilling rigs, of which 8 are in the Permian and 6 are in the Midcontinent region. The firm completed 18 net wells during the quarter with 29 net waiting on completion. In addition to its continued delineation in the Meramec play, the firm recently began completion of an increased density pilot in the Woodford formation.

Oklahoma operators trim excesses

Devon is lowering its E&P capital investment by $100 million to $1.9-2.2 billion, a common amount trimmed by the larger independents over the past couple of weeks.

The firm said its ability to reduce spending is a result of being under budget during the first half. The firm reported drilling and completion efficiency gains in the STACK and Delaware basin and supply chain initiatives that have offset industry inflation year to date.

Devon remains on track to increase its rig count by yearend to 20 from 18 at the end of June. Of the 20, 18 will be in the STACK and Delaware basin.

Chesapeake Energy Corp. plans to decrease its companywide rig count to 14 by yearend from 18 currently and 19 in the second quarter. The firm entered the year planning to average 17 rigs. It intends to place on production 20 fewer gross operated wells in 2017.

The firm currently is operating 7 in the Eagle Ford, 4 in the Midcontinent region, 3 in the Haynesville, 2 in the Powder River basin, and 2 in Northeast Appalachia.

Continental could lower its planned capital expenditures for 2017 by up to $200 million while in the range of $1.75-1.95 billion, which is expected to maintain cash neutrality at West Texas Intermediate prices of $45-51/bbl for the year. The reduction will be accomplished primarily by reducing completion crews and rigs.

The firm’s rig count for the second half is projected to average 18, with 14 in Oklahoma and 4 in the Bakken. By the end of August, Continental will have 9 operated rigs in the STACK, with 7 targeting the Meramec formation and 2 targeting the Woodford formation. It currently has 5 operated rigs working in the South Central Oklahoma Oil Province (SCOOP) targeting the Springer, Sycamore, and Woodford formations.

Continental has reduced its Bakken completion crew count to 4 and has 6 crews in Oklahoma. As a result, the firm expects to exit 2017 with a DUC inventory in the Bakken of 160 gross operated wells, including 35 already stimulated with production expected in 2018.

Continental now expects its average 2017 production will be in a higher range of 230,000-240,000 boe/d compared with its previous guidance of 220,000-230,000 boe/d. Continental expects to exit the year with production between 260,000-275,000 boe/d compared with its previous exit-rate guidance of 250,000-260,000 boe/d.

In its newly targeted Merge play of Oklahoma, Linn Energy Inc. is drilling both Sycamore and Woodford targets from multiwell pads with 2 rigs, and the next several completions are scheduled to commence early in the fourth quarter.

The firm is considering adding a rig in the Northwest STACK to test horizontal potential along with evaluating several other potential productive horizons in the area.

Linn noted that industry activity in the Northwest STACK has spiked, with 41 rigs working and 101 horizontal well permits filed in the second quarter compared with just 43 permits a year earlier.

Rockies’ drilling times shrink

Ultra Petroleum Corp. added 3 operated rigs in Pinedale during the second quarter and is currently running 7 operated and 1 nonoperated rig there. The firm expects another rig to be added by the end of August to complete its 2017 ramp up plan. In less than a year, Ultra has quadrupled its operated rig count.

The firm said it averaged 9.4 days to drill an operated well in the second quarter, as measured by when the well was spudded to when it reached TD. Total days per well, measured by rig-release to rig-release, averaged 11.4 days in the quarter. Cycle times remained flat quarter-to-quarter even though 3 rigs were added to Ultra’s fleet.

PDC Energy Inc. in Wattenberg has elected to drop to a 3-rig program in the fourth quarter, citing increased drilling efficiencies on its standard-reach, mid-reach, and extended-reach lateral wells resulting in more than 15% average improvements in spud-to-spud drill times. The firm plans to operate 3 rigs in the Delaware basin for the remainder of the year, with much of the anticipated activity focused on additional extended-reach lateral wells in the Eastern area.

Because of the increased efficiencies and adjusted timing of completions, PDC now expects to spud 155 wells and turn-in-line 133 wells for the full-year in Wattenberg compared with an estimated 139 spuds and 139 turn-in-lines previously.

Echoing what many other US E&P executives said in their second-quarter earnings reports and calls, PDC Pres. and Chief Executive Officer Bart Brookman said his firm has the “operational flexibility” to increase or decrease its rig counts depending on market conditions.

Big gas producers lift output

Antero Resources Corp. is currently operating 4 rigs and 3 completion crews in the Marcellus, where average drilling days from spud to final rig release was 12 days in the second quarter, a 4% reduction from 2016. The firm continues to increase pad sizes and is currently drilling both a 12-well and a 14-well pad in the Marcellus.

The firm is operating 2 rigs and 2 completion crews in the Utica, where during the second quarter the firm drilled its longest lateral to date at 17,380 ft.

Antero is raising 2017 production guidance by 3% to 2.25-2.3 bcfed from its previous guidance range with no change to its drilling and completion capital budget. The increase in production guidance is primarily a function of improved recoveries through advanced completions, which have averaged 2,045 lb/ft of proppant year-to-date.

Gulfport Energy Corp. has 6 operated horizontal rigs active in the Utica, where the firm’s average drilling days during the second quarter from spud to rig release totaled 18.

The firm also is operating 6 horizontal rigs in the SCOOP. Gulfport is in the process of high-grading its rig equipment and expects to return to 4 horizontal rigs in the coming weeks as contracts expire.

Gulfport is increasing its 2017 production guidance to 1.065-1.1 bcfed, up 48-53% from its 2016 average net production.