A touch of gray hair is creeping into the South Texas Eagle Ford as the play enters maturity four years after the Petrohawk discovery started the “all hands on deck” rush in October 2008.
And that gray hair suggests the play has achieved a dignified adulthood following its wild and crazy adolescent stage. After four years of spectacular growth in rig count, South Texas Eagle Ford activity flattened in 2012 as rising efficiencies in the drilling and completion process collided with constraints in regional takeaway capacity to reduce the need for rigs, even as operators generated more wells per year.
The maturity theme is a useful tool for interpreting the changes underway for oil services in the South Texas Eagle Ford.
Operators defined the boundaries of the Eagle Ford in its infancy from 2009-2010 as rig count gradually rose from a half dozen units in 2009 to 35 on average during the first quarter 2010. As the play entered adolescence, operators delineated the best rock in the condensate and volatile oil window that gracefully curves in a narrow band from the border with Mexico up to the San Marcos Arch east of San Antonio. Concurrently, rig count expanded from an average 102 in the first quarter 2011 to 180 in the second quarter 2012.
During this era, the Eagle Ford competed with other rapidly developing shale plays in the U.S., overwhelming the supply of drilling rigs and pressure pumping capacity in the domestic market. Shortages of rigs, pressure pumping equipment, labor, and the bulk goods used in well stimulation corresponded with rapidly rising costs for oil services.
Commodity prices set the tone for 2012 with interest fading in the dry gas Eagle Ford window, while oil prices stimulated interest in the under-pressured shallow oil window to the north. As maturity settles in on the South Texas Eagle Ford in 2012, operators have moved from delineation to optimization in completions, or the process of determining which combination of techniques in the engineering toolbox produce the greatest hydrocarbon recovery.
In a few cases, well-financed early movers like Pioneer Natural Resources, EOG Resources, and Anadarko Petroleum Corp, are transitioning into full resource harvest, the holy grail of the resource play model where economies of scale and broad swaths of acreage nudge E&P programs toward wealth creation after years of outspending cash flow.
In the summer of 2012, a handful of Eagle Ford operators were experimenting with drilling multiple horizontal laterals from a single well site. Pad drilling will grow in volume as operators refine the technique, creating a need for specialized self-moving, fit-for-purpose rigs on the one hand, but fewer rigs overall.
Several themes characterized the South Texas Eagle Ford during the summer of 2012, including a plateau in rig count with rig employment trending lower by yearend as optimization efforts reduce cycle time.
Secondly, the play has made a transition from a short supply of goods and services during the rapid activity escalation in 2011 into modest oversupply in 2012.
Thirdly, operators are experiencing declining costs as rates for pressure pumping services, coiled tubing, and drilling rigs pull back thanks to the equipment oversupply. For operators, total well costs in August 2012 were down 5 to 10% versus the beginning of 2012.
The rapid evolution from short supply to excess capacity reflects changes in the broader pageant of the exploration and discovery cycle.
Between January 2010 and August 2012, oil and gas operators jockeyed for position in the South Texas Eagle Ford, consummating $17.5 billion in acreage purchases, joint ventures, or corporate acquisitions as regional private independents successfully executed exit or monetization strategies. Buyers included major oil companies such as BP, Chevron, Hess, Marathon and Shell, complemented by public independents that established beachheads in the play.
Several acreage holders entered joint ventures, trading property for financing, often with foreign partners in Asia, such as KNOC, CNOOC, and Reliance Industries. Through August 2012, Eagle Ford operators had entered more than 15 joint ventures totaling $7.7 billion with roughly 75% of that investment allocated to drilling carries within a three year time frame.
Overall, transactions totaled $8.5 billion in 2010, $6.5 billion in 2011, but only $2.4 billion as of July 2012. In other words, the land grab portion of the play had passed from the scene in 2012 with the golden era stretching from late 2010 through the first half of 2011 when nearly two thirds of all transactions were consummated on a dollar value basis.
The land grab cycle was followed by a rapid escalation in rig count. Initially, natural gas drilling drove the rise in Eagle Ford activity with gas-directed rig count increasing from less than 30 rigs in January 2010 to 70 by yearend. As gas-directed rig count peaked in late 2010, oil or liquids-directed drilling became the driving force in Eagle Ford activity.
Overall, rig count grew from 100 in early 2011 to 180 by yearend among rigs specifically targeting the Eagle Ford. But the ratio of rigs drilling for gas versus oil changed dramatically. There were 67 rigs drilling for gas in January 2011 and 40 rigs targeting oil. In August 2012, the gas-directed rig count fell 40% to 40, while the oil/liquids-directed count surged by 100 units to 140 total, a 250% increase.
The rise in rig count was only part of the story. The South Texas Eagle Ford hosted the largest concentration of technology rigs in the United States. Part of this is a function of customer demographics. The majors, large independents, and a few midcaps had a preference for Tier I rigs, or units capable of horizontal drilling with automated control systems, top drives, and large mud pump packages, often configured in a modular layout that facilitated rapid mobilization between wells.
Market share for Tier I technology rigs in the South Texas Eagle Ford grew from 44% in January 2011 to 64% at the end of the second quarter 2012. In contrast, Tier I technology rigs represented 28% of total rig count nationwide. Furthermore, while South Texas Eagle Ford rig count grew 70% over the 18-months ending in the second quarter 2012, Tier I technology rig employment grew 140%.
Looked at another way, Tier I technology rigs accounted for all the rig employment growth in the South Texas Eagle Ford between January 2011 to June 2012.
In comparison, Tier II rigs, defined as traditional DE-SCR electric units, saw Eagle Ford employment stay the same over that same 18-month time frame while Tier III rigs, the conventional mechanical units that make up more than 40% of the U.S. rig fleet, saw Eagle Ford employment drop from 15 units in January 2011 to eight units 18 months later.
While it looked initially like 1,000 HP rigs might find a home in the Eagle Ford as operator efforts moved up dip to mid-depth condensate and shallow oil, the transition did not materialize. Rather, fleet expansion involved 1,500 HP Tier I technology rigs with employment expanding from 41 units in January 2011 to 96 in June 2012, a 135% growth rate.
Nearly one in four new build Tier I technology rigs nationally found a home in the Eagle Ford shale over the last 18 months.
The rapid increase in rig employment in the Eagle Ford occurred in the context of a high demand market nationally, creating the highest hourly rig rates among domestic shale plays during 2011. Rig rates for newbuild 1,500 HP Tier I technology rigs on multi-year contracts in the Eagle Ford shale reached the mid to high $20,000 range in the summer of 2011 as operators embarked on the early stages of the optimization cycle.
One year later, optimization had become the name of the game with a few operators entering the harvest stage of resource development. The latter stage often incorporates pad drilling configurations in which fit-for-purpose rigs with self moving capabilities drill multiple wells or multiple horizontal laterals off a single well site.
While average rig rates remained steady in the play thanks to multi-year contracts, rigs rolling off contracts are entering an oversupplied market. Leading edge rig rates are softening while operators are reducing the term length on contracts to six months, or less.
The South Texas Eagle Ford rig fleet remains relatively concentrated with five contract drillers representing 75% of all rig employment. Those contractors are led by Tulsa-based Helmerich & Payne IDC, who is approaching a 60-unit presence in the Eagle Ford, or a 33% share, followed by Nabors Drilling USA and Patterson-UTI who each have 25 rigs active in the play, or a combined 30% market share.
Among operators, Chesapeake Energy Corp. is the largest rig employer in the play with 25 units turning to the right, followed BHP-Billiton with an average 17 units. Marathon, at 15 units, increased rig employment in the play — mostly new build Tier I rigs — from zero in August 2011 after its acquisition of Hilcorp Resources properties. Other operators with 10 or more rigs active on average include EOG Resources, ConocoPhillips, and Pioneer Natural Resources.
Several operators, including Chesapeake Energy Corp. and Pioneer Natural Resources, have their own drilling rigs or wells stimulation crews. Additionally, operators such as EOG Resources and Pioneer Natural Resources have their own sand mining operations to provide proppant for well stimulation. Such efforts can reduce individual well costs by $150,000 on wells that typically run from $7 to $9 million.
On the well stimulation side, the South Texas Eagle Ford is looking at a 13% gain in hydraulic horsepower (HHP) in 2012, bringing regional capacity to 1,743,000 HHP. There are 65 well stimulation crews in the region with utilization averaging 96%. A representative Eagle Ford well averaged 9,300 feet in vertical depth with a 5,800 foot horizontal lateral. Operators were employing 17 frac stages per lateral using a pressure pumping spread that averaged 37,000 HHP.
Following the collapse in gas prices in early 2012, drilling slowed in dry gas shale plays nationwide.
Consequently, well stimulation capacity and drilling rigs from dry gas basins such as the Marcellus, Haynesville and Barnett shales rotated to liquids or oil basins, including the Eagle Ford shale. At the same time, capacity expansion on behalf of pressure pumping firms in response to the tight market in 2010-2011 combined to create an oversupply of crews and equipment. Average price per stage for Eagle Ford wells fell from $204,000 in 2010 as the play was ramping up, to $188,000 on average at the beginning of 2012, to $154,000 in August 2012, according to Energy Sector Analytics LLC, a Houston-based market research firm.
Operators were experimenting with propane fracs on a small scale as an alternative to slickwater fracs. Most wells used a closed hole plug and perf completion technique though there is some experimentation with packer based open hole sliding sleeve techniques.
The proppant supply shortage had also eased in the summer of 2012, though prices were up about 5% versus the first of the year, partly due to guar-related increases. Guar is an emulsifier used in cross-linked gel well stimulation for oil or liquids-based wells. U.S. Silica was establishing a sand storage facility in San Antonio at press time where it could ship unit trains of 100 or more cars carrying high-grade Ottawa sand to South Texas.
Regionally, operators focused mostly on the Eagle Ford. Other formations undergoing evaluation in 2012 included the Pearsall shale, and the Austin Chalk, although operators had reduced dry gas drilling efforts in the Wilcox and other South Texas reservoirs.
Regional constraints in takeaway capacity will keep Eagle Ford activity on a measured pace. Natural gas prices would have to increase meaningfully for Eagle Ford rig count to expand above present levels.