Players entrenched in the booming Permian Basin oil play of West Texas and southern New Mexico are working their way through the region’s growing pains—low takeaway capacity, limited workforce and logistics challenges—with aims to emerge with both success and profit from what pundits are calling one of the world’s most important oil provinces. Technological advances used to unlock the full potential of the reserves in the region’s Delaware and Midland basins are still being matured, and production is set to increase by as much as 4 MMbbl by the end of 2022, thanks in large part to new pipeline projects being brought online. The bigger picture for future activity in the area is a bit of a mixed bag.
Operators in the Permian have cut spending plans for the balance of the year, and the rig count has been on the decline over the past several months. According to Enverus Drillinginfo, the Permian rig count has dipped by nine units from mid-July to mid-August and by more than 40 over the past 12 months. The lower activity can be attributed to the large number of drilled but uncompleted (DUC) wells in the area. Almost half of the nation’s 8,100 DUC wells are located in the Permian, according to the U.S. Energy Information Administration. The backlog has led some contractors to scale back plans to introduce new equipment to the market. Liberty Oilfield Services’ CEO Chris Wright told attendees at an August energy conference in Denver that the company would wait to deploy its newest hydraulic fracturing fleet until market conditions improve.
Permian operator Devon Energy told investors in August that it has transitioned to full-field development across a significant portion of its core acreage in the Delaware Basin. The area’s Wolfcamp Formation will account for as much as 65% of the company’s development program in the coming years. The company has touted average 30-day production rates of about 2,500 boe/d from more than 50 wells across the Leonard, Bone Spring and Wolfcamp formations in the first half of 2019.
“Our outstanding results year to date are benefiting from the learning attained from our appraisal work performed in prior years,” said Devon COO Tony Vaughn. “During this appraisal activity, and our work in other plays across the company, we have a strong understanding of the subsurface that allows us to identify the best landing zones, understand parent/child dynamics, along with the appropriate well density per section and deploy optimized completion designs to capitalize on that knowledge.”
While the riddles of the Permian plays are being unraveled, challenges for the industry in the region remain ever-present. Beyond export logistics, operators are still combating steep decline curves and initial flow issues related to well proximity as well as larger, looming factors like commodity price uncertainty. With many operators deferring additional spending, the Permian will likely suffer a dip in drilling activity during the second half of the year, and perhaps into 2020. Production, however, remains forecast to increase as more routes for oil and gas out of the area open up and operators tend to some of the overhang in the region’s drilled, undeveloped well backlog.
Tools of the trade
Service giant Halliburton has worked diligently both within its walls and with clients in the field over the past few years to bring a new rotary steerable system (RSS) to market that has the ability to tackle some of the Permian’s toughest challenges. The result was the iCruise intelligent RSS that combines smart technology—advanced electronics, sophisticated algorithms, multiple sensors and survey packages, and high-speed processors—with some of the highest mechanical specifications on the market. The goal was to integrate the latest technology and provide an intelligent system to provide higher ROP, improve steering and use the latest maintenance techniques to drive higher reliability.
“Our clients using the iCruise RSS today number in the double digits,” said Faraaz Adil, Halliburton business development manager, technical, Permian Basin. “If I look at the total number of rigs that we have in the Permian, I think roughly 20% to 25% are using rotary steerable systems. We are confident that the iCruise RSS is going to gain Halliburton market share very quickly based on the performance we’ve seen and the successes we have had across the Delaware and the Midland basins.”
The iCruise RSS is designed for very precise steering. The bottomhole assembly (BHA) is modular and can be set up for drilling curves with doglegs up to 18 degrees per 100 ft. It also can be set up to drill faster laterals. The steering precision is driven by three distinct dual-phase measurements feeding into advanced control systems. The measurements are being made at 1,000 Hz allowing for very precise control of direction.
“Several of the launch models used when we were designing the iCruise system have been employed as a building block for other automation systems in the bigger picture,” Adil said. “The idea behind the whole thing was to be far more predictable and repeatable in drilling complete wells than where the industry is today. Our automation system, in general, is very different in each phase of drilling. When drilling a vertical section or laterals, the tool will actually control itself, lining up on the target and drilling with very little variation in inclination or azimuth.”
The iCruise RSS uses a new automation service called LOGIX automated drilling director, a Halliburton Sperry Drilling technology that was created around a complex digital model of the BHA and a digital twin of the wellbore. LOGIX software is installed in surface systems and supplies the commands to the downhole tool to precisely steer the wellbore through the reservoir matching the directional plan. It creates model-based optimization to drill to a plan or target on an optimized trajectory while improving drilling efficiency. It uses machine learning to continually compute the optimal course and provide steering commands to the iCruise RSS.
Halliburton continues to expand its intelligent systems initiative throughout the oilfield life cycle—from drilling to completion. On the completions side, there is the Prodigi intelligent fracturing service. Designs in unconventional fracturing require many parameters to achieve optimized stimulation treatment outcomes. The Prodigi service can automatically adjust pump rates during the breakdown process, driving consistent stage-to-stage performance, by utilizing real-time measurements and proprietary rate control algorithms. Adaptive rate control also can support a more efficient breakdown at the perforation clusters, improving the connectivity of fractures.
“The impact of execution on the success of a stimulation treatment is often underestimated,” Adil said. “People believe that if you pump a certain amount of fluid and proppant into a formation that should give you a result. That is not always the case. It is very necessary and important to understand how you pump that fluid and proppant into the formation. One of the aspects of that is how you go in and break down the formation before you actually pump fluid and proppant into it. So that breakdown process can greatly impact the final results from a production perspective as well. The Prodigi intelligent fracturing service utilizes an automated control mechanism to optimize this process and allows for the most efficient breakdown that we can achieve.”
While the tool is working, it is constantly looking at responses and taking measurements and reacting to what it detects. The major benefit is real-time optimization, matching the required rate and pressure needed. The operator isn’t exactly depending on the human sitting with the pump and adjusting the rates. The software takes control of all of that. It does not matter what time of day it is or who is there with it; it is going to perform the same way stage after stage.
“Prodigi service is constantly looking at the pressure responses when you are conducting a frac job,” Adil said. “It is picking up real-time wellbore pressure information and feeding that into the internal algorithm that allows the service to come to a decision effectively faster than a human would be able to make the same call. We try to keep the amount of information fed into the system at a minimum. The way the product is designed is that it is not dependent on a lot of information that could be variable from different sources. It is picking up the real-time pressure inputs and making decisions based on that.”
Since Halliburton rolled out the Prodigi service as a commercial tool for many of its clients across the Permian, the tool has proven its ability in both the Delaware and Midland basins.
No more cement plugs
For decades, Weatherford’s customers’ only options for openhole sidetracks were openhole cement plugs or deployment of a two-trip sidetracking whipstock system. Both of these options are costly or full of risk. Weatherford developed AlphaST, the world’s only single-trip openhole cementing and sidetrack system that enables the cement and sidetrack in a single trip for the first time ever.
“In the Permian, depending on the application and/or the client, about 10% of the wells drilled get sidetracked—planned or unplanned,” said Tom Emelander, U.S. GeoZone operations manager for casing exits, openhole whipstocks and multilaterals, at Weatherford. “The vast majority of these sidetracks are done off cement plugs. Everyone does a handful of these cased-hole and openhole systems. We do as well. But the vast majority of these openhole sidetracks are done off cement. The success rate of plugs depending on application and area—the feedback we get from our drilling services guys and from the operators themselves—is anywhere from 50% to 75%, depending on depth, hole size and formation. The typical time savings we see with the AlphaST versus a successful plug is in the neighborhood of two to three days. That is significant. That is a step change versus the best-case scenario that isn’t happening consistently. There is substantial value to the client in the form of time savings, such as fewer trips, eliminated cement curing time and eliminated failed sidetracks, which result in earlier well completion and production for each one of these wells.”
Those savings are realized when compared to cement plug or two-trip sidetrack systems. As much as half of the time, an operator is not successful on the first cement plug, meaning they will have to go and set another plug. With the second plug, the success rate could be lower because the hole already has been left exposed for, in some cases, several days. One way to counter that might be to change the operation from the first plug to the second, but that usually comes at the expense of the cement or more often in the time spent letting that cement cure, resulting in customers giving up more time or spending more money each time a plug is unsuccessful.
“As an example, looking at the average spread rate, cost of cement [and] cost of the AlphaST versus a two-plug attempt, we’re saving approximately $350,000 and a week to production time,” Emelander said. “That itself is pretty eye-opening, but when you look at it in terms of large-scale drilling—operators with 30 to 40 rigs—if they are sidetracking at that average pace across a 100-well program, you could be saving $2.2 million and 50 days to production quicker. That’s massive. That’s all money that you can put back into the budget. To get those values, we’re assuming most of the cement plugs are successful. But a couple of them are likely going to take more than one attempt. That is where you really start adding cost and days to the operation. If it is unplanned, you are going to exceed AFE [authorization for expenditure] pretty quickly.”
In developing AlphaST, Weatherford was determined to eliminate a trip compared to existing whipstock systems and eliminate the need for cement plug sidetracks. The crucial innovation was to actually save a trip out of the wellbore to pick up a dedicated drill off BHA and drill off the whipstock. Weatherford then used its proven, reliable conventional system, which facilitates setting the anchor, and engineered a new mill that attaches to the current whipstock. Customers can now drill off with attached mills without the need to come out of the hole after cementing to pick up another BHA.
“AlphaST reduces cost and risk,” Emelander said. “All the same reliable processes are utilized. We added an extra two mills, the first being a proprietary design. It is generating tremendous customer excitement.”
Shape of water
Water logistics in the Permian Basin continue to evolve as a leading challenge for producers in the region from both a supply and disposal perspective. Although water infrastructure and related logistics have improved over time, operators are still pushing to reduce completion costs and long-term operating costs for handling produced water. As completions continue to grow, operators are increasingly reaching out to third parties for cost-effective disposal and reuse options and for help in handling the growing volumes of produced water and source water needed for fracturing. On average in the Permian, the water-oil ratio is estimated at 3 bbl to 4 bbl of produced water for every barrel of oil produced. As a consequence of growth, large-scale gathering infrastructure consisting of networks of pipelines, disposal wells and recycling facilities are being permitted, constructed and operated, diminishing the need to truck water. Additional benefits include the aggregation of large volumes of produced water to support recycling and a substantial reduction in the use of freshwater resulting from changes in hydraulic fracturing fluid chemistries, which have relaxed requirements for the treatment of produced water for fracturing.
Solaris Water Midstream has been expanding its infrastructure footprint in the Permian for the past several years. With assets in the Midland and Delaware basins, the company has been recycling in the Midland Basin for more than two years and started water recycling at its Lobo Ranch facility in Eddy County in July. In its first few months of operation, Lobo Ranch recycled up to 80,000 bbl/d of produced water. In New Mexico’s Lea County, Solaris Water is mobilizing the Bronco Produced Water Recycling and Blending Center and expects to begin delivering treated water to operators from that facility in late September. The Bronco facility also will have the capacity to treat in excess of 80,000 bbl/d. Solaris Water has plans to construct additional large-scale recycling and blending facilities in Eddy and Lea counties over the next few years.
“Solaris Water’s growing integrated pipeline network in the Delaware Basin runs approximately 350 miles across Eddy and Lea counties in New Mexico serving numerous major customers and further extends into Culberson and Loving counties in Texas,” explained Solaris Water’s CEO Bill Zartler. “This system consists of interconnected, large-diameter trunk lines that support the bi-directional flow of water and related gathering systems and saltwater disposal [SWD] wells. Today the system extends 40 miles north into New Mexico from the Texas state line with permitted rights of way to extend the network even farther to the north.”
To provide perspective, most water trucks carry about 130 bbl. Solaris Water is currently moving 500,000 bbl/d in the Delaware and Midland basins—or the equivalent of over 3,800 trucks. While emerging technologies continue to play a role in the water treatment end of the business, the current focus for many in the industry is ramping up operations to meet producers’ current and future needs.
“I think what’s different now is the scale of water systems, the volumes being moved, working with multiple operators at the same time and aggregating their produced water before treatment and recycling,” Zartler said. “The water quality specs for fracking have also changed. While operators have a standard spec, today the level of treatment required to meet this spec has been reduced. Today, the industry is more focused on reducing total suspended solids, iron, H2S and bacteria and is not as concerned with dissolved solids. We are no longer looking to clean produced water to almost potable levels. With slickwater fracs and more effective chemistries and friction reducers, operators can effectively use saltier water for fracking, which has dramatically reduced the need for treatment and related costs.”
"With slickwater fracs and more effective chemistries and friction reducers, operators can effectively use saltier water for fracking, which has dramatically reduced the need for treatment and related costs.”—Bill Zartler, Solaris Water Midstream
He continued, “The water business is also a business in transition, from small outfits with a handful of trucks and a couple of disposal wells to a full-fledged midstream service entity. As it evolves, what we see today is either upgrading or consolidation of saltwater disposal companies into companies with large pipeline networks and a focus on gathering systems and multiple SWDs, which requires a larger amount of capital. We’re also seeing producers continue to focus on capital efficiency. Producers made the evolution 25 years ago to divesting their natural gas and crude gathering systems. Water midstream is evolving in the same way. Given the intense focus on not spending cash and the ability for the upstream industry to raise money, certainly in the public markets, producers are doing what they can to eliminate capital expenditures for services a third party can provide at a fair price. We think we will continue to see producers evaluating the sale of their midstream water assets to raise capital and outsourcing their water needs to proven midstream players that have large integrated water systems in place—systems they continue to expand.”
The Permian’s shift to a more sustainable water model is not lost on the management of XRI. The company purchased the water treatment and recycling division of Fountain Quail Energy Services in April and recently completed its Northern Delaware Basin Supersystem with water pipeline infrastructure spanning more than 125 miles throughout the core areas of development activity in New Mexico’s Eddy and Lea counties. The cost of water treatment and recycling technology is now attractive versus the all-in cost of water disposal.
“The economics of treatment and recycling on a full-cycle basis are superior to saltwater disposal of produced water for our customers,” XRI CEO Matthew Gabriel said. “When paired with the nonpotable water sourced on our owned water midstream systems in the Delaware and Midland basins, and broad water distribution networks of approximately 300 miles, it is now possible for our customers to reuse, blend or swap 100% of their produced water to obtain recycled water of virtually any specification.
“XRI is focused on the continued development of our midstream asset base, providing long-term takeaway of produced water from our customers and subsequently treating that water to meet the water quality specifications for a multitude of other users on the network. Providing large-scale treatment and connected infrastructure utilizing automation and advanced water data systems is the optimum way to ensure that XRI is providing the most cost-effective and long-term water management solutions to serve the evolving needs of the Permian Basin’s most prolific oil and gas producers.”
A pair of new laws, New Mexico House Bill 546 and Texas House Bill 3246, also have gone a long way to clearing up any murkiness surrounding produced water ownership. Both determined that oil and gas operators control the produced water and they could then use, dispose of, transfer or convey to recycling companies, which then take over legal responsibility. The New Mexico law went into effect in July, followed by the Texas law in early September. With that question answered, longer-term players and private-equity groups have a clearer path to returns when deciding to invest in the sector. Many believe that the growth potential if properly funded, could yield a new, robust service industry, not unlike the conventional midstream services model.
“As E&P companies continue prolific development of the Permian Basin, responsible and effective water management is integral to the success of the industry.”—John Durand, XRI
“As E&P companies continue prolific development of the Permian Basin, responsible and effective water management is integral to the success of the industry,” said John Durand, XRI president. “The evolution of water midstream will likely mimic the conventional midstream natural gas sector, where a few large entities that, through consolidation, form large interconnected combinations of assets and systems. Like the midstream natural gas pipeline networks of today, it is not difficult to envision a scenario where large water ‘super networks’ will exist to maximize efficiencies and ensure that companies such as XRI continue to provide large-scale, full-cycle water management solutions that focus on the principles of resource preservation and social responsibility in order to maintain viability and sustainability for the industry.”
Blinded by the light
The pursuit for oil in the desert of West Texas has been a draw for oil and gas operators for almost 100 years. From the earliest days of the Westbrook Field discovery and the Santa Rita No. 1 to today, the Permian Basin reinforces the old wildcatter’s adage—the best place to find oil is in an oil field. There are times, however, where oil and gas exploration has unintended consequences, and everyday technology—something as simple as a light bulb—becomes a source of contention.
When operator Apache started looking at a new trend in the west end of Reeves County, Texas, back in 2015, there wasn’t much buzz about the area. It was gas prone. The geology was complex. It was off the radar of most industry players. By the time Apache announced its findings for the area it had dubbed Alpine High, it had established a vertically stacked resource with estimated reserves of 75 Tcf of rich gas and 3 Bbbl of oil in place. And it has only gotten bigger. The discovery and subsequent expansion did not go unnoticed by a curious neighbor to the south. Roughly 20 miles from the Reeves County border situated in the Davis Mountains of Jeff Davis County, the McDonald Observatory, part of the University of Texas, was established in 1932 to study the cosmos in one of the darkest places on the planet. The observatory, home to the world’s third largest telescope, had concerns about encroaching light from oil and gas development that has crept nearer to its Mt. Locke location. But something that could have become adversarial instead became a welcomed collaboration.
Apache and the observatory joined forces with dark skies initiative coordinator Bill Wren and the McDonald Observatory to implement best lighting practices to protect the dark skies of West Texas. The operator conducts weekly audits of about 1,600 lights across Alpine High to ensure compliance.
“You want to mount high and aim low,” said Wren in an August interview with Marfa Public Radio. “Keep your light on your site. Another thing that is in the recommended lighting practices is to go with a low-temperature light.”
Other companies are also looking to reduce their light “sky print” and adhering to the observatory’s published “Recommended Lighting Practices” guide that is endorsed by the Permian Basin Petroleum Association, Texas Oil & Gas Association, American Petroleum Institute, University Lands and the Texas Independent Producers and Royalty Owners Association. Elements being used by the industry to cut down on light pollution include proper shielding and aiming of existing fixtures, which improve visibility and reduce wasted up-light. There also has been the deployment of new lighting systems that take advantage of light-emitting-diode technology and promise better directionality and reduced fuel consumption.
“As we work to keep the skies dark in West Texas, our emphasis is light positioning and light fixture shielding,” explained Apache spokesman Phil West. “With these two techniques, which control the light direction, the majority of the light impact is mitigated. Light sources that are properly aimed and shielded are more efficient, and that generally requires fewer lights throughout our operations.”
In July Apache donated $257,000 to McDonald Observatory that will be used to fund the observatory’s ongoing efforts to preserve the dark West Texas skies that make research possible and provide unsurpassed views of the universe to visitors.
Check out the other "2019 Permian Playbook" chapters that appeared in the October issue of E&P magazine:
Producing Unconventional Wells without Electricity
Other U.S. Gulf operators, including Chevron, Exxon Mobil, BHP, Shell and Hess, said June 3 they are monitoring the storm but have not evacuated workers so far.
The company postponed its FID for the Rovuma LNG project, which had been expected this year, in March as the coronavirus outbreak and an oil price slump forced firms to delay projects and slash spending.
The French energy giant will acquire a 51% stake in the Seagreen 1 project, which, once completed, will be Scotland’s largest offshore wind farm.