Drilling efficiency is the phrase on everyone’s lips, as the bar keeps getting set higher and higher. Industry observers weigh in on getting the most drilling done in the least time for the least money.
Reducing drilling costs is an everyday topic in the oil patch and there is no simple answer. Is that site a good location? What about the drilling rig? Is the infrastructure ready? And are all the vendors in place? One bad decision can escalate the costs.
The Permian Basin is one area that sets the pace for drilling. Long before horizontal drilling became an accepted and refined operation, people were drilling vertical wells throughout the area. While some basins today focus primarily on horizontal drilling, drillers here are heading downward and sideways. People in the industry are always searching for ways to drop those drilling costs.
The topic gathers such widespread interest that it was the focus of a two-day seminar Dec. 5-6 in Houston organized by American Business Conferences. Among the invited speakers was Jeff White, vice president of operations for Diamondback Energy Inc., in Midland.
“Our horizontal play in the Permian is just now developing, whereas a lot of other basins like the Bakken and Marcellus only do horizontal drilling,” White said. “They don’t have vertical plays like the Permian and that’s probably why horizontal drilling didn’t take off as soon.”
When the price of gas dropped, activity slowed or shut down in the gas basins and drilling equipment was sent to the Permian Basin, where drilling has remained steady, according to White.
White, who spoke on the topic of “Demonstrating How a Leading Operator Has Driven Down Horizontal Completion Costs in the Wolfcamp and Cline,” accentuated the amount of planning required before drilling begins. 
“One of the things that drives costs up is not having the infrastructure in place to dispose of water without having to haul it,” said White, who has been with Diamondback since September 2011. His previous experience includes stints at Anadarko and ConocoPhillips, as well as consulting work.
Before a well is drilled, many hours of work go into planning. In the long run, these meetings can keep drilling costs down.
White considers the proper selection of vendors an important factor in drilling. One condition that has kept costs down in the last couple of years is the increasing number of hydraulic fracturing companies that have moved to the Permian Basin. “There used to be five, and now over 20 companies are here,” he said.
“On big frac jobs, we have 15 to 20 vendors out there doing different things. I want everyone to be at our pre-job meetings. Everybody has a job to do and they need to know what it is and when they are expected to do it. One vendor not doing his job can cause you a train wreck. It could cost you the well if some party doesn’t take care of his piece of the business,” he said.
One aspect of the job is the proper placement of frac pits, according to White. “We don’t want to be transporting water a long distance. And an electrical grid needs to be in place. When we complete wells we need power to the well. We don’t need crews standing around waiting for generators. The electrical grid has to be ready to go.”
The completions phase also needs timely coordination with all the vendors. “You can avoid costly cleanouts if you have the frac equipment already there. You have to get the well bore cleaned out so you can finish completion of the well.”
Completions can be a 24/7 job for seven to 10 days and is an orchestrated event with all parties involved. “It’s a domino deal—if the sand doesn’t show up for the next stage, people are sitting around waiting for it. Meanwhile, we’re paying stand-by time. Each party has an important piece of the completion.
“You can bring in the rig, stand it up, drill the well, and complete it. But if there is no way to dispose of the water via pipeline” the cost goes up on that well. “Hauling water can drive up the costs by several hundred thousand dollars,” White noted.
Acknowledging the commonly cited fact that vertical wells are less costly to drill than horizontal wells, White remarked that a typical vertical well could run about $2 million, as compared to $8 million for the horizontal.“ It depends also on how deep you drill a well,” he said.
The Energy Advances New Mexico organization posted on its website an estimated cost of drilling wells in the Land of Enchantment vs. the Lone Star State. “Interviews with those familiar with the industry suggest that drilling prices in New Mexico average about $215 per drilled foot, and range from $150 to $300 per drilled foot,” noted the group’s website. “It is estimated that the cost to drill a well in the San Juan Basin [in northern New Mexico] is valued at $1.2 million…. [whereas] the cost to drill a well in the Permian Basin is valued at $1.6 million.”
Eric Fox, who writes for the multimedia financial services company The Motley Fool, reported in August 2012 on oil and gas companies cutting development costs. Newfield Exploration, he said, is drilling wells quicker and drilled a well in the Williston Basin in 20 days compared to an average of 35 days in 2011. Anadarko, he noted, is decreasing development costs through more efficient drilling across the company’s extensive set of onshore plays. In the Eagle Ford Shale, for example, they drilled one well in just under seven days.
Whiting Petroleum, headquartered in Denver with an office in Midland, is moving toward multi-pad drilling and estimates this technique will help cut the cost of wells by $2 million, Fox wrote.
Rigs and all the equipment to run them play an important role in keeping drilling costs down. Newer rigs are more efficient and even moving them to nearby locations is becoming a matter of “rolling” them to the new site.
The U.S. Energy Information Administration noted in its Sept. 11, 2012, report that pad drilling and rig mobility are leading to more efficient drilling. Moving a drilling rig previously involved disassembling the rig and then reassembling it at the new location, even if it was only yards away. “The cost of rigging down and rigging back up can be high enough that producers may find it more efficient to build a road between two pads, transport the rig intact, and have it arrive ready to drill the next well,” the EIA report stated.
James Nash with Nabors Industries Ltd. calls the increased efficiency a matter of “technology. Mud motors, bits, and 1600 horsepower pumps” are improving drilling. “We own our top drive company. We own 18 drilling rigs and expect that number to be up to 22 by the end of the year [2012], not counting workover rigs,” he said.
Based in Houston, Nash is operations manager of the Lower 48 for Nabors and came to the Permian Basin about six months ago to help in the Midland office, which covers West Texas and southeast New Mexico. He has worked in the oilfield 37 years, 26 of those with Nabors.
The company’s website notes that Nabors “owns and operates the largest land-based drilling rig fleet in the world and has one of the largest workover and well servicing rig fleets in the U.S. and Canada. The land-based drilling rigs generally consist of engines, a drawworks, a mast or derrick, pumps to circulate the drilling fluid (mud) under various pressures, blowout preventers, drill string, and related equipment.”
For the past decade, Nabors has been investing in upgrading the capacity of its rigs in order to drill more efficiently and to reduce the time required to move between wells, the website noted.
“Out here, the average time to drill a well is 12 to 18 days,” Nash said. “That’s for a well that is 11,000 to 12,000 feet. We have some deeper wells in Loving County that are going 15,000 to 16,000 feet and are taking 20 to 30 days to drill.”
A majority of Nabors’ rigs are designed for horizontal drilling. “Technology is changing every day,” Nash said. “We have the latest equipment with bits, mud motors, more horsepower pumps. We invented our own top drive technology.”
Nabors is one drilling firm that the majors turn to, according to Nash. “We drill for Shell, Chevron, Devon, Oxy. And when things slow down for the majors, some of the large independents call on us.” Those independents can include Energen, St. Mary’s, Approach, COG, Comstock, and Anadarko.
“I think drilling will pick up after the first quarter of the year when everyone gets their drilling budgets,” Nash surmised.
John Rich, vice president with Lantern Drilling in Odessa, echoed Nash’s assessment of drilling improvements: better bits, downhole mud motors, and new rigs.
“The drill bits that have no moving parts drill faster and deeper. They perform and last a lot longer. Downhole mud motors run 120 rpm in the hole. The motor allows you to turn the drill bit at 120 rpm instead of 60 rpm. We can make more hole faster,” Rich said.
With oil prices up in recent years, numerous companies are replacing old rigs and equipment with newer technology. “Everyone is buying new equipment,” he said. Until the recent purchases and rig upgrades, some companies were still using equipment from the 1950s and 1960s.
Lantern, owned by Forrest Oil, offers a fleet of 15 rigs ranging from pulling units to 18,000 foot capability, according to its website. Five of the rigs are new-build diesel electrics; two 1500 HP SCR rigs and three 1600 HP Quicksilver rigs; eight rigs ranging from 500 to 1000 HP; and two workover/pulling units with 450 HP.
All the rigs have digital instrumentation. “This computer-controlled equipment tells you more about what you are doing in the hole. We stop and run a string to see if we are drilling straight or if we’re drifting. It used to be a mechanical process using a wire. Now it is done electronically and as often as you want it,” Rich said.
He also pointed out that a lot of science has been conducted on drilling mud, resulting in better additives that make it more controlled. “We have to get cuttings out of the well and the mud does that,” he said.
“So many variables are involved in drilling a well,” Rich added.
The company has rigs working in the Texas Panhandle, in Pecos and Reeves counties in West Texas, as well as in East Texas, in the Eagle Ford area, and in Oklahoma. In 2011, Lantern drilled more than 1 million feet on 100 wells, which figures out to be 10,000 feet for each well.
“Computers and software make drilling much more efficient,” Rich said. “The old technology is inefficient.”