The outlook for the Permian Basin’s unconventional region compares favorably to that of the prolific Bakken and for good reason: “The Midland Basin/Wolfcamp-Cline is similar to the Bakken in terms of gross thickness in its shale, which means more resources,” Darrel Koo, senior associate, energy research at ITG Inc., told attendees at Hart Energy’s recent DUG Permian conference in Fort Worth, Texas. The industry could see up to 1.8 MMbbl/d of oil production growth from the Permian by 2025, Koo continued, with a best-case estimate of 3.2 MMbbl/d of oil production by 2025.

A long-time oil-producing basin, the Permian’s unconventional region is attracting fresh interest from major companies like Apache Corp., which is focusing on the play as one of its four core areas of production. “The Permian’s not a one-trick pony,” said John Christmann, Apache’s executive vice president and COO, during DUG Permian. “We have more formations and multiple basins to continue to produce. The nice thing about this basin is everything is stacked, which creates multiple plays and multiple targets in every net acre you own.”

Permian Basin leads domestic market resurgence

Stacked pays rival unconventional plays for activity ramp-up.

By Richard Mason, Chief Technical Director

The Permian Basin is on fire.

And it’s not just the blazing West Texas sun, either. Rig count is back above 500 units for the first time since 2012, according to Baker Hughes, while horizontal and directional rig count has climbed above 300 units—and counting.

The technological effort to develop tight oil via horizontal drilling and multistage fracturing has come full force to the Permian Basin, promising another new chapter in a historic narrative that spans 90 years.

Operators are delineating multiple benches in the Wolfcamp Shale in both the Midland and Delaware basins—the geologic gift that keeps on giving in both geographic extent and geologic column height.

Meanwhile, high oil prices are sustaining lucrative conventional drilling in traditional Permian targets, providing further support to the hottest domestic market in the U.S.

The Tao of the Permian Basin lies in two twin basins flanking both sides of a buried structure known as the Central Basin Platform. The Permian, in fact, resembles a butterfly with open wings. The yin and yang of today’s Permian is evident as horizontal Wolfcamp delineation efforts move south of the New Mexico line in the Delaware Basin on the west and, in the Midland Basin, migrate north out of the original core in Crockett, Reagan and Irion counties into Midland and Martin counties.

The numbers tell the story.

Horizontal well count was up 25% in the Permian’s Delaware Basin in 2013, according to a Morgan Stanley & Co. LLC research report, while horizontal permits jumped 33%—the largest regional increase in the domestic market during 2013. Only the Eagle Ford has witnessed more horizontal wells.

And it is getting better. While the 1,500 horizontal permits filed by Permian operators in first-quarter 2014 ranked a distant second to the high-flying Eagle Ford Shale, momentum is clearly swinging toward the Permian, where horizontal permits jumped 87% sequentially in first-quarter 2014.

Four Permian Basin counties account for the majority of the activity increase, including Midland and Upton counties in the Midland Basin and Reeves and Ward counties in the Delaware Basin. Reeves witnessed a 15-unit jump in horizontal rig count to 50 active rigs during first-quarter 2014 to pace the Delaware, while combined horizontal rig count in Midland and Martin counties rose from 15 to 37 units during the same time frame.

The transition to horizontal drilling is the main narrative in the ongoing Permian resurgence. Originally, operators employed horizontal drilling to exploit the Bone Spring along both sides of the Texas/New Mexico border. In 2011, for example, the Delaware Basin sported 60 rigs drilling horizontally, representing 75% of horizontal work in the Permian. Delaware horizontal rig count has added more than 100 units since.

But the story of late centers on the rapid expansion of horizontal drilling in the Midland Basin, which has vaulted from 20 units in 2011 to 145 units at the end of April 2014. Currently, horizontal rig count is almost evenly split between the Delaware Basin at 52% and the Midland Basin at 48%. Combined, both basins support more horizontal rigs than any other region in the U.S.

Furthermore, the Permian is still in delineation mode when it comes to the Wolfcamp Shale. Operators are pushing lateral lengths, experimenting with downspacing, packing more stages along the lateral and tweaking downhole completion recipes as they extend the prospective Wolfcamp across the Delaware and Midland basins.

The optimization portion of the tight formation development cycle is evident, primarily in Bone Spring targets in southeastern New Mexico. However, the Permian as a region is still early in the overall tight formation development cycle, and widespread resource harvest sits a couple years out into the future. One proxy for the evolution is pad drilling. Multiwell pads were few and far between in early 2013—less than 10% of horizontal wells. Currently pads are found on more than 20% of horizontal wells, and the number of wells per pad continues to increase, serving as a harbinger of the future.

Multiple operators are active in the play, ranging from the majors and former majors to privately held companies. Since most acreage is already leased or held by production, acquisitions have become the primary means of expanding positions in the Permian. The region tallied more than $25 billion in transactions in 2011 to 2013, leading all other regions, including the Gulf of Mexico.

A flurry of energy IPOs in 2013 focused primarily on the Permian as management teams backed by private equity capital found that the stock market supported stellar pure play acreage valuations that would underwrite expensive horizontal exploration.

And it’s just getting started. The Permian will be to stacked formation plays as what the Eagle Ford and Bakken are to unconventional shales. The latter feature 91 m (300 ft) of hydrocarbon-bearing strata. In contrast, the Permian incorporates multiple benches in a stacked formation column spanning more than 457 m (1,500 ft) and nine separate geologic targets, depending on locale.

It seems that after 90 years, it’s déjà vu all over again in the Permian Basin.

Midstream scrambles to keep up with burst of production

Activity spike causes project expansions.

By Joseph Markman, Associate Editor

They’re drilling for hydrocarbons with the urgency of the 1920s, when Ira Yates sold leases from his front porch in Pecos County, Texas. This time, they’re going at it horizontally, and for midstream operators, this era of the Permian is a bonanza.

“We’re seeing fantastic returns in the play—40% to 100% [internal rates of return],” said Tomas Ackerman, managing director of investment firm Natural Gas Partners. “It’s one of the best plays in the world.”

The Permian’s EOR activities have driven demand for CO2, which Kinder Morgan Energy Partners LP plans to meet by building the 343-km (213-mile), 8.5 MMcm/d (300 MMcf/d) Lobos pipeline to move CO2 from Arizona to the Cortez pipeline in New Mexico. The $1 billion project is expected to be in service during 2016.

Drilling escalation is powering a surge in daily crude production, forcing midstream operators to scramble to avoid bottlenecks.

“We are excited about the growing production forecast in the Permian Basin,” said Bruce Heine, Magellan Midstream Partners’ director of government and media affairs. Tulsa, Okla.-based Magellan has two major pipeline systems originating in the Permian.

“Our Longhorn pipeline, which has been safely transporting crude oil from the Permian to Houston since the second quarter of 2013, has a capacity of 225,000 bbl/d,” Heine said. “We are currently increasing the capacity of Longhorn to 275,000 bbl/d.

“Our second project is the BridgeTex pipeline, which is a 50:50 joint venture with Occidental Petroleum,” he said. “This system, which is currently under construction, will have a capacity of 300,000 bbl/d when it becomes operational in mid-2014.”

Ackerman’s Natural Gas Partners is backing PennTex Midstream Partners LLC’s expansion in the Delaware Basin, the southwestern slice of the Permian. PennTex purchased a majority interest in Atlantic Midstream LLC in February and renamed it PennTex Permian. By the end of the first quarter PennTex Permian had put low- and intermediate-pressure gathering pipelines and associated compression into service. The company expected a July completion date for its 1.7 MMcm/d (60 MMcf/d) cryogenic natural gas processing plant in Reeves County, Texas, in the Wolfcamp play. Ackerman looks forward to being part of the Permian’s ramping up, especially in terms of investment opportunity in the midstream space. Technological advances in drilling and completion give the Permian an economic edge over other plays.

“In the midstream business, the key is to be responsive to a producer’s needs,” he said. “That’s the key to being competitive in a hot region like the Permian: You have to deliver on what you promise.”

Managing worker exposure to silica-based products in sequences of shale reservoir stimulations operations

By Donna S. Heidel, Kimberly Carson, John Baker and John Stangline, Bureau Veritas North America

Employing an occupational and safety management system to shale gas reservoir stimulation operations assures that worker health and safety are considered at each step in the hydraulic fracturing life cycle. Management systems also support the ongoing reassessment that is required as new information is developed about the hazards of new and existing proppants and other chemical hazards, resulting in sustainable health and safety performance.

Exposure to crystalline silica particles of respirable size has been identified as an occupational health hazard associated with hydraulic fracturing operations. When inhaled, respirable-sized particles can enter the gas-exchange regions of the lung, according to a June 2012 hazard alert from the Occupational Safety and Health Administration (OSHA) and National Institute for Occupational Safety and Health (NIOSH) that was titled, “Worker exposure to silica during hydraulic fracturing.” Exposures are typically due to the mechanical handling of large volumes of dry crystalline silica. Future innovations, including the use of nano-enabled proppants and lubricants, may introduce occupational health hazards that have not yet been fully characterized.

Uncertainties exist about exposure risks and the appropriate controls needed to mitigate the potential risks to worker health. These factors prompt the adoption of a robust management system to ensure that worker health and safety are considered at each step in the development, use and ultimate disposal of silica and other proppant materials.

Industrial hygienists at NIOSH identified eight points of dust generation present during hydraulic fracturing operations, according to an article in the Journal of Occupational and Environmental Hygiene titled, “Occupational exposures to respirable crystalline silica during hydraulic fracturing,” by E. Esswein, M. Breitenstein, J. Snawder, M. Kiefer and K. Sieber. These eight points can be broken down into three groups: dust generation during sand-mover loading, pumping operations and outside the hydraulic fracturing process.

Full-shift respirable dust samples indicated personal exposures to silica that exceeded the OSHA-calculated permissible exposure limit, NIOSH-recommended exposure limit and American Conference of Governmental Industrial Hygienists’ Threshold Limit Value. No studies have been published presenting exposures to advanced proppants or nano-enabled lubricant stimulations operations. Further toxicological studies are needed; however, NIOSH has recommended the implementation of a “comprehensive occupational safety, health and environmental management plan to minimize occupational exposure risks.”

Controlling silica and nano-enabled dusts at the point of generation is the preferred method of engineering control as it reduces the amount of dust entering work areas. Source controls, when included in the design of the process and equipment, are typically more effective and less expensive than when included as a retrofit to existing equipment, according to “The Power of Collaboration: Professional Safety,” by J. Gambatese, M. Hallowell, F. Renshaw, M. Quinn and P. Heckel.

Process enclosure and exhaust ventilation are established methods of controlling hazards and can be adapted to hydraulic fracturing with some consideration given to the operational requirements of the process. Dust emissions associated with mechanical action and drop points, such as those associated with pumping operations, may be adequately controlled by passive enclosures such as stilling curtains, tent enclosures or enclosed chutes. Alternate proppant delivery systems, including the use of gravity to feed sand to the transfer belt, are also available and are expected to reduce exposure risks associated with the delivery of sand to the transfer belt.

Dust collection systems and enclosures can address emissions from proppant handling systems, but dust from the ground on the site and roads leading to the well pad can also be a source of crystalline silica exposure, particularly in dry areas and seasons. Water, amended water and ground coverings (such as rubber pads) can be used for site dust suppression.

While easy to overlook, dust release from workers’ clothing is a source of exposure. If the clothing is not cleaned or removed, the silica-containing dust may be transported to the workers’ homes and families. Using a HEPA vacuum, engineered air showers and wet methods can control airborne dust while cleaning work clothing.

Including these and other appropriate controls into the design of stimulations operations and the associated process and equipment to control worker exposure risks requires a systemic approach for identifying health hazards associated with both known and novel materials and assessing and controlling exposure risks.

An occupational health and safety management system (OHSMS) provides a structured method to assess and improve occupational health and safety (OHS) performance through the effective management of hazards and risks in the workplace. An OHSMS also provides a framework for including OHS considerations into the design, operation, maintenance and eventual repurposing of processes and equipment. In addition, an OHSMS supports the inclusion of OHS into the development of new methods for fracturing, including nano-enabled proppants and lubricants. Based on Dr. W. Edwards Deming’s “Plan-Do-Check-Act” cycle for monitoring business performance on a continual basis, OHSMS aligns OHS performance. In this way, it keeps workers free from occupational injuries, illnesses and exposures, with the achievement of business goals.

Unconventional activity picking up steam in Permian Basin

Contributed by Canary LLC

A couple of months ago, Texas oil producer Occidental Petroleum began an “unconventional push” in the Permian Basin, where the new activity will complement the company’s ongoing conventional program there.

“They [Occidental] look at their diverse Permian acreage as a strategic advantage and their holistic, more conservative approach as part of the execution strategy,” research analyst Jennifer Warren wrote in a recent column for Seeking Alpha. “The EOR business is the cash cow to help double drilling rigs over the next three years to accelerate overall Permian resources growth.”

Occidental is not alone. The Permian Basin in West Texas and southeast New Mexico has been seeing a surge of activity in recent months. Oil companies are flocking to the area in droves in search of unconventional hydrocarbons.

In early April, Oryx Midstream Services LLC of Midland, Texas, announced it had received an equity commitment totaling up to $300 million from private investors to pursue midstream opportunities in the basin.

Also that month, Denver-based Outrigger Energy LLC announced an expansion of its own midstream capabilities in the Permian. This news followed a similar announcement for the company’s Delaware Basin system in March.

Only a few years ago, the oil and gas industry viewed the Permian as a fading resource. But in 2010 shale oil exploration took off in the Midland formation. Operators drilled nearly 2,300 exploration wells that year, and in 2013 they drilled more than 10,220 wells.

Today the Permian is a key location for unconventional energy operations.

In a recent report, the Independent Petroleum Association of America wrote, “Production in the Permian Basin reached two million barrels per day in the early 1970s, declined to 850,000 barrels per day in 2007, [and] has since rebounded to 1.3 million barrels per day.”

And that number continues to grow: As of the first week of April, 520 rigs were at work in the Permian, while there were 214 in the Eagle Ford Shale, 185 in the Williston/Bakken and 66 in the Mississippian. What’s more, nearly 40% of the active rigs in the Permian are now drilling horizontal wells, and that percentage is expected to increase.

The Permian’s varied resources

Not only is the Permian Basin massive (the oil field is approximately 402 km [250 miles] wide and 483 km [300 miles] long), it’s diverse, too: The site comprises multiple conventional and unconventional plays and a wide variety of geological formations.

One of the basin’s appeals is its stacked plays, multiple producing zones that can be accessed with both vertical and horizontal wells. This feature allows companies to extract oil and natural gas that could be too costly to produce under other circumstances.

The Permian’s varied resources include the Wolfcamp Shale Formation, which is 457 m to 792 m (1,500 ft to 2,600 ft) thick at a depth of 1.6 km to 4.8 km (1 mile to 3 miles). The formation, which the Lubbock Avalanche-Journal called one of the “hottest unconventional plays around,” is believed to extend throughout most of the basin.

The Wolfcamp Formation is located within the Delaware Basin portion of the Permian, which also is the site of the booming Bone Spring Formation and the Avalon Shale.

Houston-based Nuevo Midstream recently completed a major processing capacity expansion for shale gas in the Delaware Basin. CEO Jay Lendrum said that many of the “big players,” including ConocoPhillips and BHP Billiton Ltd., have a presence there as well.

The Cline Shale, also described as the Lower Wolfcamp, has been making news as well. It spans roughly 113 km (70 miles) wide from east to west and about 225 km (140 miles) from north to south, with a target zone for oil production that is between 61 m and 152 m (200 ft and 500 ft) thick.

Last year the Cline Shale was estimated to hold 30 Bbbl of recoverable oil. By early 2014, there were reports that those estimates may have been overly optimistic. While the amount of recoverable oil there is still up for debate, most analysts believe that the massive formation still holds potential.

Just warming up

Unconventional activity has been a bit slow to become a major presence in the Permian Basin. Until recently, the Permian was dominated by conventional hydrocarbon wells, which are drilled with rigs that are positioned vertically. Unconventional hydrocarbons are found in shale and other hard rock formations, and extracting the hydrocarbons calls for the more complex and costly technique of horizontal drilling.

Only in recent years in light of higher oil prices and the prospect of boosting production have companies chosen to commit to expensive horizontal drilling and hydraulic fracturing to extract the plentiful hydrocarbons in the Permian Basin. Now conventional and unconventional programs are working side by side there.

Expanding opportunities in the basin were among the motivating factors behind Canary LLC’s move into the area through the recent acquisition of American Wellhead LLC, a wellhead sales and service company for the Permian Basin and New Mexico.

“Our national customers wanted a location in the Permian Basin, which currently represents almost 25% of the U.S. oil field,” Canary CEO Dan Eberhart said. “The Permian is shifting from vertical to horizontal drilling, and that kind of unconventional drilling is right in our wheelhouse.”

Unconventional activity in the basin absolutely is on the increase, Lendrum added. “Based on historical drilling results, drilling efficiency improvements and increased drilling activity, our production forecasts for the area continue to rise,” he said.

Jeff Stevens, president and CEO of Western Refining Inc., expressed similar sentiments after his El Paso, Texas-based company announced a new pipeline project in the Permian’s Delaware Basin April 17. “Given the growth of light crude oil and condensate production in the Delaware Basin, we believe there is an opportunity to continue to expand and enhance our logistics capabilities,” he said.

Clearly, with additional companies announcing new projects in the Permian Basin on a monthly—and sometimes weekly—basis, unconventional activity will be strong in the basin for some time to come.

Increasing frack efficiency in the Wolfcamp Shale

Engineered completion design improves productivity.

Contributed by Schlumberger

The Wolfcamp Shale play in the Delaware Basin of West Texas has high production potential and is liquids-rich. The reservoir, which is characterized as unconventional, consists of laminated layers with high clay content and is deep and highly pressured. Operators in the area are developing the play, mainly with horizontal wells.

Recent studies and evaluations of production logs indicate that it is incorrect to assume that rock properties in the horizontal wells are homogeneous, and not all stages and/or perforation clusters contribute to production equally, if at all. There is, therefore, a need to acquire accurate log measurements in the lateral to evaluate the properties of the heterogeneous formations and thus enable an engineered completion workflow that will deliver optimum production rates.

In the past, Clayton Williams Energy has had limited success stimulating its horizontal wells in the Wolfcamp. These issues can be partially attributed to the highly laminated, heterogeneous nature of the formation. The equidistant geometrically spaced perforation program that is typically selected when log data are not available or are not considered in the design process can result in high pressure differentials between perforation clusters within a stage. The consequences can include ineffective stimulation treatment, such as not placing the designed amount of sand, screening out or skipping stages in parts of the lateral that are landed in higher stressed rock.

Clayton Williams Energy experienced frequent instances of incomplete proppant placement and screenouts, which greatly reduced well productivity and operational efficiency.

The company contracted Schlumberger to perform openhole logging services in the lateral section of several horizontal wells in its Wolfcamp acreage and then integrate these measurements through an engineered staging and perforating workflow to provide an optimized completion design. Measurements of petrophysical and geomechanical rock properties were acquired using ThruBit logging services. This “through-the-bit” compact logging system provides a full measurement suite from a small-diameter quad- or triple-combo tool string. The tool can withstand pressures up to 15,000 psi and temperatures up to 177 C (350 F). With a diameter of only 2? in., the tool is sufficiently slim to pass through the center of most drillpipe, jars and collars and out of the opening of a specialized drillbit.

The acquired log data were used as inputs for an engineered staging and perforating design workflow. The workflow was implemented using the Mangrove engineered stimulation design in the Petrel platform, which used the log measurements to locate fracture stages and intelligently place perforation clusters within a given stage in similarly stressed rock based on reservoir and completion quality.

The use of log measurements in the lateral, combined with the engineered completion workflow, resulted in the first stimulation treatment being placed 100% as designed with no screenouts or skipped stages. This first well showed a 39% increase in cumulative oil production after 90 days compared to the best offset well completed with the conventional geometric spacing of fracture stages. Three wells with log measurements and the engineered completion design delivered, on average, a 103% increase in 90-day cumulative barrels of oil equivalent compared to three geometric wells in the same area. This significant improvement in oil production indicates that more stages/perforation clusters were contributing to production thanks to increased reservoir contact.

Based on the success of the first wells, Clayton Williams Energy used the logging technique and engineered workflow to evaluate and design completions for 10 additional laterals. The workflow continued to improve stimulation effectiveness and productivity by increasing the percentage of stimulated perforation clusters. A 28% increase in designed sand volume was pumped, and the operator also realized a 33% increase in successful stages where more than 75% of the designed sand volume was pumped. In addition to improving well productivity, the workflow benefited operational efficiency, saving an estimated average of 1.5 days per well on coiled-tubing cleanout operations.