We have not seen end of Shale or Deepwater technology efficiencies. Its accelerating . EX: Cramer talks to Core Labatories

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Multi-well pad drilling—when multiple wells are drilled from a single drill site—is allowing companies to produce oil more efficiently and at a significant cost savings, resulting in record production for shale oil producers.

The market for multi-well pad drilling technology is expected to surpass US$180 billion by 2024, according to a report by Global Market Insights, as oil & gas sector companies look to more unconventional extraction methods to meet rising demand for energy resources. Analysts expect to see the most growth in the North American onshore market segment due to the large number of shale exploration and production projects.

“U.S. producers are enjoying a second wave of growth so extraordinary that in 2018 their increase in liquids production could equal global demand growth,” the International Energy Agency (IEA) said in a February report. “We are seeing United States production rising very, very dramatically before our very eyes and that’s likely to continue in 2018,” Neil Atkinson, head of the IEA oil industry and markets division, told CNBC. The IEA believes the United States may well surpass Saudi Arabia and Russia as the world’s leading energy producer by 2019.

Not to be outdone, Canada’s oil producers are also working hard to grab a bigger piece of the global oil market, with a focus on the Duvernay and Montney formations, which “could rival the most prolific U.S. shale fields,” reports the Financial Post. “Canada, by contrast, offers many of the same advantages that allowed oil firms to launch the shale revolution in the United States: numerous private energy firms with appetite for risk; deep capital markets; infrastructure to transport oil; low population in regions that contain shale reserves; and plentiful water to pump into shale wells.”

Multi-well pad technology behind shale oil boom

Traditional extraction methods involve drilling down vertically from a new pad—the location that houses the wellhead—for each new well, which means that even if the new location is merely a few yards away the rig needs to be disassembled, hauled to the next pad and then reassembled. This entire process can be time and labor intensive not to mention costly to both the company and the environment.

“Pad drilling allows producers to target a significant area of underground resources while minimizing impact on the surface,” states the U.S. Energy Information Administration (EIA). “Concentrating the wellheads also helps the producer reduce costs associated with managing the resources above-ground and moving the production to market.”

Multi-well pad drilling has “played a linchpin role in opening up capital-intensive tight formation oil plays  . . .  as part of a broader revolution in drilling and completion techniques,” according to Richard Mason, Chief Technical Director for industry publisher Hart Energy. “Pad drilling enabled the industry to employ factory-like economies of scale to shorten cycle time and increase rig productivity so that hydrocarbons are brought to market more quickly or, in the case of batch completions, in greater volume.”

Two innovations in the oil & gas sector are driving the market for multi-well drill pad technology: horizontal drilling and hydraulic walking systems.

Game-changer: horizontal drilling

Advancements in horizontal drilling is a close second to hydraulic fracking in terms of the technologies behind the increased levels of crude oil production in the United States and Canada over the past decade. The EIA recently reported that increasing nationwide oil production over the last few years has been largely driven by new shale oil well production which accounted for 54 percent of the country’s overall oil production in 2017. According to the EIA, higher productivity can be linked to growing use of hydraulic fracturing and the increased drilling of longer horizontal wells, which have brought down costs sharply.

Horizontal drilling has reduced the amount of time it takes to drill wells and is especially suited to unconventional oil plays such as shale, Leonard D. Jaroszuk, President and CEO of  Enterprise Group Inc (TSX:E), told INN. “Well pockets can have multiple zones at various depths, the product in the ground can be extracted from multiple points horizontally or side pockets that may have been missed in past single well sites.” Enterprise Group provides access to specialized, high-end technology and equipment for companies in the energy industry.

Majority of multi-well pad drill rigs designed with a hydraulic walking system

“One of the industry’s more recent innovations, pad-to-pad moves, underscores the efficiency gains from rig mobility and pad drilling,” according to the EIA. These pad-to-pad moves were made possible by the advent of hydraulic walking systems, or walking rigs, which were first employed in shale operations in 2004.

Walking rigs are equipped with hydraulic rams that lift the drill rig and a track system that moves the rig to another location. This technological advancement allows companies to transport fully-assembled drill rigs from pad to pad without the cost and loss of productivity associated with rigging down and rigging back up. Drill rigs that can walk themselves to the next well site have also led to the design of more efficient and versatile pad configurations, cutting the time needed to drill multiple wells.

While multi-well pads using walking rigs accounted for about 5 percent of wells drilled in U.S. unconventional plays, by 2013 that number had reached 58 percent. “Today the number of these new mobile rigs has surpassed the number of older conventional units,” reported E&P Magazine.

Increasing efficiency, reducing costs and minimizing environmental footprint

The idea for onshore pad drilling has its roots in offshore drilling operations, where multiple direction wellbores are drilled from one platform. The advent of horizontal drilling coupled with improved rig mobility made possible by hydraulic walking systems allows companies to drill multiple wells (as many as five to ten) going in different directions from a single pad at surface—targeting several formations from a central location—while at the same time reducing both operational and environmental costs.

Pad technology allows companies to split containment and completion costs across multiple wells. “Multi-well pads lower site moving costs and improve efficiency as equipment is used on the same site for multiple wells and projects. This method drills several wells horizontally on one large pad rather than a vast number of singular wells spaced out across the frontier,”Jaroszuk told INN.

Rigs can be mobilized within a matter of hours rather than days, and only one pipe line is needed for multiple wells at one site, rather than a pipeline for each single well location. “A large and long-time client of ours, that is working in the Montney formation of Alberta and BC, has seen significant increases in downhole production and efficiencies in site costs over the years after transitioning from single well sites to multi-well pads. These benefits have played a big role in further implementation of multi-well pads,” said Jaroszuk. “We have grown alongside
this shift and have adapted and built our equipment to facilitate these pad site requirements and efficiencies.”

While a single pad can house as many as 10 to 12 wells, oil companies are finding the “sweet spot” is between four and six wells per pad. According to a report by Transparency Market Research, the multi-well pad market is forecast to expand significantly by 2025 with much of that growth being “dominated by the less than 6 pad size.”

Drilling multiple wells from one location also has environmental benefits in that it causes significantly less surface disturbance and means less road construction and less truck traffic—which translates into decreased diesel emissions. “Accessing multiple wells at one location also minimizes the environmental footprint because significantly less land surface is disturbed. Companies only need to build one road to a multi-well pad, whereas single well locations each need their own road access,” explained Jaroszuk.

The Takeaway

Multi-well pads, horizontal drilling and walking rig technologies have allowed the North American shale oil producers to compete as leaders in the global markets. With the growing demand for energy and fuel, that trend is likely to continue as US and Canadian oil companies find more ways to maximize production efficiencies through cost-cutting technologies.

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some shale related techs that will bring costs down, increase production etc:

 

Dow recognized for resin-coated proppant helpful to shale oil

A special proppant designed by Dow for the shale oil and gas industry helped the Michigan chemical giant earn a prestigious Edison award. The awards are given every year to honor excellence in innovation. Dow’s trademarked VORARAD downhole sequestration technology earned a silver award.

According to Dow, the resin-coated proppant can inhibit harmful isotopes, like radium, from rising to the surface, which aides in minimizing the amount of naturally occurring radioactive material that is brought to the surface during flowback production.

The coated sand is able to trap Radium particles downhole and also create a stronger network of frack matrices by limiting the amount of sand that can travel back to the surface after pressure

pumping is complete and a well is on production.

Dow’s lab tests on the material show that it can reduce Radium in isotopes of water by as much as 65 percent.

The ability of the resin-coated sand to stay secure downhole also helps to reduce pipe and pump blockage.

In addition to the resin-coated sand product created for the unconventional oil and gas industry, Dow was also recognized for work creating better photovoltaic elastomers, packaging material, ecofriendly coloring for cottons, and heat-resistant packaging.

Being recognized with an Edison Award has become one of the highest accolades a company can receive in the name of innovation and business, the awarding entity explained. “The awards are named after Thomas Alva Edison (1847 to 1931) whose inventions, new product development methods and innovative achievements that changed the world, garnered him 1,093 U.S. patents and made him a household name around the world.”

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Emerson's IoT system enhances shale oil production, monitoring

A new technology offering created by Emerson could use data and IoT to optimize production in existing unconventional wells and also help with new well designs. Brian Blakey, director of business development for Emerson’s E&P Software segment, recently outlined the company’s cloud-based system they call the Paradigm K.

The software is a native-to-the-cloud system that is reliable and secure across all platforms. Using a unique algorithm and data set created by surface and subsurface data, the K can help with optimizing current production over the life of a well and help engineers design production and flowback schedules for new wells.

With the K, “any oilfield instrument can now be enhanced with subsurface information to enrich

the measurements they provide,” Blakey said, “extending their application across all physical domains including facilities, wells, fractures, reservoirs,” all of which can be tied to historical, real-time or forecasted data.

The system models the oilfield as one large system and doesn’t separate surface equipment and variables from downhole pressures or permiability factors. Because it is connected to the cloud, it can run simulations in minutes rather than hours or days. The system can also connect to exsiting sensors and incoroporate stored data or live-data streams to create simulations or produce production optimization plans for things like gas injection on a producing well.

The major purpose of the system is to run in the backround and montior operations, looking for unique events that need to be dealt with, Blakey said.

“Rapid changes in unconventional wells can be monitored and optimized,” he said. “We can assure maximum production performance off of only one month’s worth of production data.”

To learn more about the system and how it impacts equipment operations, allocation and fiscal metering, Emerson has put out a webinar.

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In Terms of the Bakken

The phrases, words and terms that reveal the evolution of the Bakken. From energy corridors to long-reach laterals, the Bakken shale play has fostered the growth and use of industry phrases that now define the U.S. These are the most important.

From North American Shale Magazine's 2019 Bakken Report: 

Tim Wallace believes the shale energy services industry is on a path to make better use of data to improve performance, much like artificial intelligence applications with predictive analytics and IBM’s Watson computer. The Bakken shale play has evolved from an undeveloped unconventional oilfield into a globally recognized hydrocarbon producer capable of impacting world markets. At one time, the play consisted of only a handful of wildcatting operators and pioneering energy service firms willing to invest time and money into drilling and hydraulic fracturing technology unproven in the region—or anywhere else in the world. From the early days of Hail Mary fracks in Eastern Montana to the Parshall field to the latest iteration of the Bakken, the Williston Basin’s most-important geological formation has supplanted its place in the energy history of the world. In doing so, the Bakken has revealed itself as a massive, light, tight-oil-producing shale formation capable of yielding more than one million barrels of oil per day. During its rise as a global energy phenomenon, the Bakken has supplied oil and gas industry stakeholders, decision makers, investors, executives and

the general public with a never-ending vocabulary list capable of defining the Bakken at the particular time during which a phrase or term was spoken or referenced most prominently. Understanding the evolution—including the past and the near-term future—of the Bakken means understanding the time-linked terminology of the play.

Words From the Well Pad

Held By Production
From the mid-2000s to 2013, the Bakken’s rig count rose dramatically before stabilizing in the high hundreds. Knowledge of the Bakken formation’s possibilities as an oil producer were well-documented and the play was creating unprecedented oil and gas production, construction and workforce opportunities in the areas most targeted. The success rate on a new well horizontally drilled and hydraulically fractured in the Middle Bakken formation of the greater Williston Basin was nearly 100 percent. As small-, mid- and large-scale operators rushed to secure future drilling and production rights throughout western North Dakota and eastern Montana, the play yielded a three-letter acronym capable of summing up this era of the Bakken’s evolution: HBP (Held-By-Production).

To secure drilling rights and future production opportunities, E&P’s needed to secure their lease rights on contracted acreage. Doing so required the operators to drill at least one producing well on their contracted acreage within a specified period from the lease signing (typically three years), to avoid violating the terms of the lease, and jeopardizing the validity of the lease. “When you are scrambling to get a lease Held By Production, you kind of put economics on the back burner,” said Ken DeCubellis, the acting CEO in 2013 for non-operator Black Ridge Oil & Gas.

During the time of HBP activity, operators paid higher prices per hour to keep a drilling rig spudding wells. Less-efficient, older rigs remained in service to keep up with demand. The HBP era was the end of a time when services and strategies were less focused on efficiency and cost-savings and guided instead on securing a future at any cost.

Infill Development
After most of the Bakken’s acreage was HBP’ed and operators had the opportunity to focus more on developing—rather than securing—what they had, most began proving out and delineating the possibilities. Infill development was a term used to explain the strategies of operators as they looked to place future wellbores into specific geographical zones and specific and horizontal lateral lengths. Those focusing on infill development were those capable of moving past the initial rush to secure acreage. Infill development spawned several innovative drilling, completion and production strategies that are still deployed in shale fields across the U.S.

Multiwell Pad Drilling
The success of the infill development era in the Bakken was made possible due in large part due to multiwell pad drilling. Because operators no longer had to drill a single well on a lease and then move a rig to another lease also waiting to be HBP’ed, operators could leave a drilling rig on a single pad longer. The practice allowed for multiple wells to be placed on a single pad. Pads started to get bigger and more elaborate. Walking drilling rigs capable of deploying hydraulic lifts to move the rig from one spud hole to another greatly decreased the time it took to go from one wellbore to two wellbores on a single pad. From a single pad, operators learned they could place multiple wells and target the same, or different formations while still giving them the ability to effectively drain their reservoir through methods available at the time.

Energy Corridors
The North Dakota Department of Mineral Resources created the first-ever energy corridors. The term was used to describe a top-surface geographic orientation that maximized industry’s access to well sites while minimizing their presence on the landscape. Spacing units that once showed random wellbore lines running in all directions and at different lengths transformed into more unified images showing wells running in unison in a single direction. North Dakota energy leaders utilized 1,280-acre spacing units to create a uniform pattern of development that helped with pipelines, electrical lines and traffic patterns.

Decline Curves
With each new operational advancement in the field, every well has become better and holds more promise than previous versions. The advancements could be linked to drilling more precise wellbores or fracturing more of the reservoir through new technology or approaches, but either way, decline curves have been a topic since the early days of the Bakken. Operators, analysts and investors all like to talk about how fast a well will decline in production. The initial production rate (linked to a period like 30 days or 3 months) is continuously rising in the Bakken. Decline rates have also risen, showing that new fracking and drilling techniques are making wells produce more oil at higher rates over a longer period.

Long-Reach Laterals
In the early development of the Bakken formation, most laterals were drilled to 8,000 feet or less. By the time engineers and investors were referring to long-reach laterals, the length of a lateral had changed. Most long-reach laterals placed in the middle Bakken today extend to three miles or roughly 13,000 feet. More efficient drilling bits, extended-reach coiled-tubing spools and more powerful drilling rig systems now allow operators to drill longer laterals, which they say can produce more oil from a single well.

Flaring
Often misunderstood as a practice of wasting or getting rid of unwanted associated gas produced during the oil retrieval process, the term flaring drew national attention to the Bakken. Still a challenge that operators deal with today, flaring has referred to the venting of associated gas that takes place due to inadequate or a lack thereof of takeaway or gathering infrastructure. Technology creators, midstream companies, investors, policy makers and the public have all played a strong role in the usage of the term. In the early development days of the Bakken, flaring was common across the play and more than two-thirds of all gas produced in the play was flared. Today, infrastructure has been installed to take away gas streams in accessible locations. For the remote and hard-to-reach areas of the Bakken, technology providers have created economically feasible options to capture and remove associated gas from the play.

Spud-To-TD
Advancements in mud motors, drill bit materials and strategies to reach total depth on a well have come a long way. In the early days of the Bakken, a drilling rig crew typically required 45 to 60 days to drill an 8,000-foot well from spud (the surface hole) to the toe of the horizontal (total depth). The term became important and often referenced when the drilling rig count declined in the Bakken and other U.S. shale plays while production and activity levels remained. The U.S. Energy Information Administration also began tracking drilling rig counts and how efficient the rigs in each play were as the Spud-to-TD times fell across the U.S.

DUCs
From late 2014 through 2017, the Bakken experienced a major decrease in activity due to low oil prices. Operators were unable to continue at their planned activity levels and had to pull back certain operations. Many began holding off on completing wells that had been horizontally drilled and were waiting to be hydraulically fractured before going on production. Research analysts began tracking the number of DUCs, or wells that were drilled but uncompleted. The state of North Dakota did the same. Some operators had to choose whether to invest or continue with a drilling contract and drill new wells, or spend their money completing wells. DUCs are still tracked today but have less prominence in the national context of shale oil production.

Words Away From the Wellhead

Crude-By-Rail
Oil takeaway capacity via any means has always been an issue in the Bakken. As the Bakken’s production grew from the mid 2000’s to now, there has always been a disproportionate amount of takeaway infrastructure—pipeline, rail or truck—to match the supply from the play. Between 2013 and 2016, one of the prominent means to move Bakken oil to the East or West Coast was via rail. The reference to the transportation style helped advance the tank car specifications used to move oil across the country. Investors tracked the usage of crude-by-rail and the practice spawned the growth and importance of another Bakken staple.

Transload Facilities
The geographic sprawl of the Bakken puts wells in remote locations that are tough to get to or take a long time to return from to a major community. Transload facilities started to rise in popularity as the play developed. Operators, midstream firms and construction or logistics teams needed to more-efficiently and economically bring in and store equipment, goods or materials. Several facilities grew to offer sand storage, piping and casing yards and oil storage or offtake infrastructure connected via pipeline to larger pipelines running out of the region.

Saltwater Disposal Wells
Like most shale plays, the Bakken system produces high volumes of saltwater brine during production. SWDs, or saltwater disposal wells, have grown in existence throughout the play. Wells are drilled into the Dakota formation where produced water is injected underground or stored at a SWD facility.

Lower-For-Longer
At the start of the oil price downturn at the end of 2014, investors, analysts, oil price predictors and oil company executives all used the phrase lower-for-longer to insinuate which direction they believed oil prices would head in the months ahead. The term was present in the shale world’s lexicon for roughly two-and-a-half years and brought on another term.

Breakevens
As operators began to find ways to maintain operations, workforce numbers and production numbers, the term breakeven was introduced into the Bakken scene and has been referred to ever since. Investors, operators and service companies all began to explain their breakeven costs. The term refers to the price point oil has to trade at for the investment of an oil well, service or operation to keep the company from losing money. Breakeven price numbers were estimated for geographical regions of the Bakken and were impacted by several factors, including infrastructure availability, lease operating expenses, and the initial rate of return a company was willing to take at any given oil price.

Cash Flow
With investors now looking to benefit from previous investments into shale energy production companies increasing, many oil and gas production executives are telling the industry that their plan for operation will remain within cash flow. Before the current investor push, operators were willing to outspend their yearly cashflow by taking on debt to drill and frack new wells. The goal was to grow production. Today, with a push to please investors, operators are focused more on operating within cash flow and limiting operations based on the amount of money they have generated from existing operations.

Two Million Barrels
The main trend over time for Bakken oil and gas production is associated with increases. The Bakken formation, which currently accounts for nearly 95 percent of all the oil produced in North Dakota, has been pumping out more than 1 million barrels of oil per day for several straight years. Government officials and industry have both pushed for the Bakken players to continue the production increase trend in the coming months and years and work to surpass 2 million barrels per day.

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Hess Produces Record-Breaking Test Well In Williston Basin

Oil Patch Hotline

Thu, 05/02/2019 - 10:09

Hess Corp. has produced a record-breaking 24-hour test well this month in McKenzie County, N.D., surpassing all records for U.S. land wells, according to an article in the website of the Oil Patch Hotline, an oil and gas trade publication for the Williston Basin.

“This was a barn burner,” said Hotline Publisher Dennis Blank. “The highest IP tests recorded before this on new horizontal Bakken wells were in the range of 3,000 to 4,000 barrels of oil equivalent per day.”

Hess said the An-Bohmbach-153-94-2734H set a new record 24-hour IP at 14,662 boe/d. The well produced 10,169 barrels of crude oil and 26,960 Mcf of natural gas and is located in Sec. 22, T153N-R94W. This new record breaker followed an earlier April 5 record of 10,626 boe/d on a companion horizontal well in the same pad.

“It was a great well and a great result,” said Hess President Greg Hill. “We achieved a very high rate IP, and it confirmed that our acreage performed very strongly in comparison to other operators.”

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Current Characteristics of Bakken Well Completions

As the well count in the Bakken or Three Forks shale formations continues to grow, the strategies deployed to hydraulically fracture each new well have changed when compared to previous approaches.

 

As the well count in the Bakken or Three Forks shale formations continues to grow, the strategies deployed to hydraulically fracture each new well have changed when compared to previous approaches. A combination of factors has helped usher in a new fracture design and strategy used by many of the operators nearly every six months for the past several years. New mechanical downhole technology used to perforate and then plug a portion of the wellbore off allow for more precise puncture placements into the wellbore. Dissolvable material, referred to as a diverter, is being widely used to section off parts of a fracture network for a specified period, all to ensure each section of a wellbore gets its desired attention from perfs or proppant and isn’t compromised when other sections are getting fracked. Downhole analytics and data sets are being captured through fiber optic cable. And, petroleum geologists continue expanding on their ever-evolving understanding of the

rock at the micro level. All of these factors are also present during a time when many new wells in the Bakken and Three Forks formation are infill wells placed on an existing pad or next to a parent well previously drilled, fracked and brought onto completion.

The interplay between the parent well and the child, or infill, wells has nudged engineers and completion consultants to factor in the effects of placing and then stimulating a wellbore close to an existing wellbore. Despite the new matrix of factors impacting the overall effectiveness of a typical Bakken frack design, Bakken and Three Forks wells are surpassing previous production expectations by continuing with a focus on fracture optimization.

Optimized Completions Unlock Bakken Value
Continental Resources, one of the largest Bakken producers to date, has reported a noticeable uptick in well production from 2011 to the present. The uptick is based on a combination of well placement and better frack jobs. In early 2018, Continental put three wells into its all-time top five producers list because of optimized completions. Each of the three wells averaged more than 1,500 barrels of oil per day for the first 30 days.

The completion changes by Continental have also produced better returns per well. In 2011, a Continental well drilled and completed at an oil price of $65/b would yield a rate of return (ROR) of roughly 15 percent. By 2018, Continental was reporting a 140 percent difference from 2011. A well drilled and completed at $65/b yields a 140 percent ROR. For Continental and several other major operators, the focus on optimized completions has pushed the boundary of the core of the Bakken. Some operators now consider the core much larger than previously thought when new completion designs are deployed.

Marathon Oil Corp. has expanded its core acreage using area-specific completion designs. A four-well pad in Marathon’s Ajax area located in Dunn County, North Dakota, produced roughly 2,400 barrels of oil equivalent for the first thirty days. “Strong early results in the Ajax mark another important step forward in our ongoing efforts to extend the core of our Bakken acreage position,” said Lee Tillman, president and CEO of Marathon. “Through enhanced area-specific completion designs, and a lot of hard work from our Bakken team, we continue to meaningfully uplift the quality of our inventory.”

Committed To The Next Generation Of Completion Design
No Bakken operator has touted its success with fracture design enhancements in the Williston Basin more than Whiting Petroleum. The operator believes it has always been ahead of the competition with testing and deploying new designs and methods. This year Whiting announced it was now using its Generation 5.0 design approach.

The new approach centers around the idea of optimizing the completions to the well spacing and geology of each individual well. For infill wells the strategy is to concentrate more of the stimulation near the infill wellbore, lower the amount of sand used, place more entry points and use more diverter material. For wells further away from other wellbores, Whiting looks to create a mix of far-reaching fractures and near-wellbore concentration while using more sand, fewer entry points and diverter material to ensure all entry points are connected.

No matter the well, Whiting now builds calibrated models for every area, uses multivariate analysis to understand which completions factors impact production most and then works with service companies to ensure they have the latest technology. The main factors Whiting focuses on with new wells is entry points, frack stages, total fluid, proppant, diverters and lateral length.

Investing In The Frack
In early 2018, shale pioneer Liberty Oilfield Services issued an IPO. The fracture design and pressure pumping experts at Liberty have shown how profitable and important the fracturing segment of shale, the Bakken included, can be.

While Liberty has been providing returns to shareholders, it has also continued investing in its suite of fracture-related products. The company has created a proprietary and trademarked FracTrends database that includes results from more than 60,000 wells along with analysis tools. Another trademarked product Liberty calls Fraconomics, allows clients to use big data to find ways to lower a cost of a barrel of oil. To help customers in close proximity to populated areas, Liberty has created a Quiet Fleet that features technology designed to minimize noise pollution created during pressure pumping operations. And, along with last-mile logistics for proppant-to-well timing, the company has also partnered with CAT to provide predicative maintenance management on equipment at the well site. Liberty’s focus isn’t just on the strategy for proppant placement or the use of diverters. The company now tracks, to the minute, the efficiency and activity of its frack fleets. Doing so helps the company greatly reduce client non performing time.

Next Gen Frack Firms On The Way
In addition to the constant research and roll-out of tooling and proppant by major energy service firms, the evolution of the fracking sector has spawned several new firms designed to meet the needs of the modern market.

Axis Energy Services represents a group of companies working to give operators more options with modern well designs and longer lateral lengths. “For too long, E&P companies in the U.S. have had two choices for completions. They could use coiled tubing with reliability issues in longer laterals, or stick pipe requiring too many companies on site—often without the right equipment or crews,” said Wendell Brooks, CEO. “The mission of Axis is simple: to offer our customers a third option to reach new levels of efficiency.”

John Schmitz, executive chairman for Axis, has also discussed the changing face of shale. “As the shale revolution enters the phase of capital efficiency and manufacturing growth, operators can’t afford to have legacy business plans and equipment slow them down or eat into their returns,” Schmitz said. “We formed Axis based on listening to our customers on the new business model and new equipment needed to get wells to production optimally and quickly.”

Lime Rock Partners, a group linked to several shale plays including the Bakken, was an investor in Axis. The company uses data to determine drill-out times prior to starting the process and has new workover rigs and completion specialists focused on optimizing completions for long-lateral shale wells.

To reduce the always-present challenge of frack hits between parent wells and infill wells, Reveal Energy Services has created a new product called FracEye. The system allows operators to make timely adjustments to wells being fracked on multiwell pads that feature parent and child wells. The system categorizes the type and severity of interwell communication by measuring the pressure response from a parent well as hydraulic fracturing proceeds normally in child wells. Geoscientists and completion engineers can use the data to determine if, or to what severity, a frack hit is taking place. The system looks for direct fluid transport from wellbore to wellbore, fluid migration increases, instantaneous pressure response in an offset well or, hopefully, if there is no signal of pressure change in a neighboring well.

Austin, Texas-based Seismos received $10.5 million from investors to harness a software-based technology to also better understand frack hits. Through its product Seismos-Frac, engineers can adjust treatment solutions on the fly. The technology was developed in conjunction with Stanford University faculty.

National Lab Frack Attention
At the national level, several research institutions from the University of North Dakota’s Energy and Environmental Research Center to Oak Ridge National Lab continue to assess, test and research novel or intricate methods to better understand the future of fracking.

Oak Ridge researchers are using a combination of neutron and x-ray scattering to make fracking more efficient. The team is testing the possibility and effectiveness of introducing ultrasonic (acoustic energy) to the downhole rock prior to fracking to increase porosity and permeability once the stimulation takes place.

“It's all about supplying energy into the formation to release hydrocarbons,” explained ORNL researcher Joanna McFarlane.

“Think of a sponge filled with water,” Richard Hale, another ORNL researcher added. “The water doesn’t come out of the pores until you squeeze it. Acoustic energy is really, really good at squeezing these pores. In small core sample–size experiments placed in acoustic baths, we can see the oil flows easily and rapidly from the rock.”

Ultrasonic techniques have previously been used to clear debris near the surface of a well. ORNL researchers believe the same technique might be applicable 8,000 feet below the surface.

A team of researchers at Los Alamos National Lab believe shale stimulation will benefit from understanding previous tectonic movements and water seepage forces not previously considered. A mathematical model shows how branches form off vertical cracks along the wellbore during the fracking process. Further research, they believe, will help engineers better understand how to optimize fracture pumping rates and the viscosity of the fluids pumped.

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Permian Firm Aims for 25-percent Headcount Growth

The energy services firm Wood has ambitious employee growth plans this year in the Permian Basin.

“If we haven’t created 500 new jobs in West Texas by the end of the year, I’ll be disappointed,” Andrew Stewart, CEO for Americas Asset Solutions with Wood said Tuesday on the sidelines of the 2019 Offshore Technology Conference (OTC) in Houston.

Approximately one-half of Wood’s approximately 4,000 employees based in U.S. shale basins work in the Permian, where the company is engaged in various pipeline, power and even solar projects in the region. Stewart said that the firm currently is advertising for more than 100 craft professionals, and he noted that the company is looking to hire employees – who would receive full benefits packages. Some of the specialties the company is recruiting for include operations and maintenance specialists, mechanical fitters, instrumentation pros, welders and others.

“Sixty percent of our payroll is craft professionals,” said Stewart. “Everything that’s been built and designed has to be maintained.”

Although Wood has had a presence in the Permian for more than two decades, the company – like other energy services firms – has reported strong growth in the region. In fact, Kerry Sedge – Wood’s communications director – confirmed  that Wood’s headcount and revenue growth in 2018 outpaced general production growth in the basin.

Wood, which has long specialized in designing and building pipelines and shale facilities, is also branching out its engineering, procurement and construction (EPC) capabilities. Stewart pointed out the company is diversifying its expertise to include power projects (solar and co-generation), fabrication and operations and maintenance. Some of the firm’s customers include operators such as ExxonMobil unit XTO, Anadarko and Shell as well as midstream players such as Navitas.

Sedge also noted that Wood is adding a digital element to its Permian service offerings. She explained that the firm is developing a “CoLab” facility in Houston that will integrate virtual reality, data analytics, automation and control robotics, process optimization and asset integrity, block chain and cyber Internet of Things and other systems and tools.

Stewart pointed out that Wood’s increasingly diverse client base, coupled with various digitalization components, should enable employees to enjoy more career continuity by developing their skill sets across a “rich variety” of projects.

“We want to be the employer of choice by having employees have a career basis rather than a project basis,” he concluded.

[ceo_energemsier + 1,818]

Most US Offshore Resources Not Up for Grabs

Ninety-four percent of the United States’ offshore resources are not available for investment.

That’s what Eric Oswald, vice president for the Americas at ExxonMobil, revealed during a presentation at the Offshore Technology Conference in Houston, Texas, on Wednesday.

“You guys know how much of the U.S. offshore is available for investment? … Six percent. Ninety-four percent of our nation’s resources offshore … are not available for us to invest in,” Oswald told delegates attending the presentation.

“Who’s losing there? I mean it’s the country, right? It’s a huge amount of potential lost there … That’s an astonishing number,” he added.

According to a Bureau of Ocean Energy Management fact sheet (BOEM), U.S. Outer Continental Shelf (OCS) production accounts for about 18 percent of domestic crude oil and four percent of domestic natural gas supply. In fiscal year 2016, federal leasing revenues for the OCS were approximately $2.8 billion, the fact sheet highlighted.

The mission of the BOEM is to manage development of U.S. OCS energy and mineral resources in an environmentally and economically responsible way, according to the organization’s website.

Oswald has worked for ExxonMobil for almost a decade, according to his LinkedIn page. He started as an exploration manager in Europe in 2009, before becoming vice president of business development and exploration in 2011. He took on his current role in 2014.

[ceo_energemsier + 1,818]

Rystad Energy predicts offshore has tremendous room for growth

The Offshore Technology Conference (OTC) in Houston, Texas celebrates its 50th birthday this week, begging the question – what will the next 50 years hold for the offshore market?

Rystad Energy, the independent energy research and consultancy headquartered in Norway, has analysed the historic investments and oilfield service purchases of the world’s 50 000 oil and gas fields. While the forecast is uncertain, their analysis paints a picture of how offshore could contribute to the future of the service industry.

“Total greenfield project sanctioning, summed up to the present day, only accounts for 40% of estimated volumes of offshore projects ever being sanctioned. Likewise, the brownfield market has only begun, with total historical expenditures accounting for only about 20% of estimated brownfield spend over the projects lifetime, leaving 80% of brownfield spending to the future. And the decommissioning market is still in its nascent form,” says Audun Martinsen, head of oilfield services research at Rystad Energy.

 

Exploration

 

Rystad Energy estimates that around 800 billion undiscovered barrels of oil and gas equivalents exist globally, hinting that exploration will still be in business in the next 50 years.

 

“However, we expect offshore’s appetite for exploration to continue to weaken long term as more potential resources are discovered. Exploration will likely be forced into deeper and more remote waters, which could be too expensive to develop given the availability of other competitive sources of supply,” Martinsen said.

 

Greenfield

 

Greenfield projects are new developments of new oil and gas fields. Historically, sanctioned greenfield projects have racked up total investments of about US$3 700 billion in real dollars worldwide. In total, greenfield sanctioning has likely only achieved 40% of its potential with reference to total global reserves.

“This means that there is tremendous room for growth,” Martinsen added.

 

Brownfield

 

Brownfield projects are expansions or upgrades of existing oil and gas fields. Of the 3 000 oil and gas fields producing today, 50% could still be producing in 2030 due to improved depletion rates through the use of advanced technology. In addition, upcoming projects already under development or expected to be sanctioned represent an additional 2 500 oil and gas fields.

“Assuming that oil and gas will still be consumed for petrochemical use and power production through 2100, we expect to spend five to six times as much on brownfield services as what has been spent as of today,” Martinsen remarked.

 

Decommissioning

 

The most immature market in the upstream oil and gas market is decommissioning. Rystad Energy estimates that only 3% of necessary decommissioning expenditures has already been spent, which entails the cost of removing, plugging and abandoning existing and to-be developed oil fields.

“Decommissioning represents a very interesting market for service companies, but in terms of size it is a relatively small US$1 800 billion market,” Martinsen said.

 

Maintenance and operations

 

The maintenance and operations service segment is naturally the market with the most volume of work ahead, with 58% of the market to be spent in the future representing US$20 500 billion in expenditures.

 

“Well Services and Commodities, Drilling Contractors, EPCI, and Subsea are equally large markets which we expect will make significant contributions to the service sector in the next 50 years,” Martinsen commented.

Commenting on the overall findings, Martinsen concludes:
“Despite oil price downturns, the shale revolution and OPEC market share wars, offshore continues to thrive and has much to offer the future.”

[ceo_energemsier + 1,818]

Breaking NEWS!!!!

Rystad Energy ranks the cheapest sources of supply in the oil industry

 

Published by John Williams, Digital Assistant Editor
Oilfield Technology, Thursday, 09 May 2019 10:30

 

In a major turnaround, North American tight oil is emerging as the second cheapest source of new oil volumes globally, just shy of the Middle East onshore market.

That is the conclusion of Rystad Energy’s latest cost of supply curve update, ranking the world’s total recoverable liquid resources by their breakeven price.

“As the majors are struggling to replace conventional liquids, a wealthy source of additional resources is tight oil,” says Espen Erlingsen, head of upstream research at Rystad Energy.

Tight oil – such as onshore shale oil in the US – has witnessed an impressive turnaround over the last few years. In 2015, North American shale ranked as the second most expensive resource according to Rystad Energy’s global liquids cost curve, with an average breakeven price of US$68/bbl. The average Brent breakeven price for tight oil is now estimated at US$46/bbl, just four dollars behind the giant onshore fields in Saudi Arabia and other Middle Eastern countries.

“The North American tight oil industry has changed considerably since 2014, as it has proven to be a competitive supply source in a low price environment,” Erlingsen added. “While costs for tight oil have been reduced, the resource potential has grown considerably over the last four years.”

Rystad Energy, the independent energy research and consultancy headquartered in Norway, estimates that total recoverable resources from North American tight oil has more than tripled since 2014.

For oil companies struggling to replace conventional resources after years of disappointing exploration results, tight oil simultaneously offers a base for growth, increased flexibility, and attractive returns.

Whereas offshore normally needs 7–12 years to recover costs, tight oil typically requires only 2–4 years.

“Tight oil is a short cycle investment with a relatively brief lead time from the sanctioning of new wells to the start of production. This gives E&P companies the flexibility to adapt to market conditions and easily change activity levels,” Erlingsen remarked. “In the ever-changing oil price environment, this implies tight oil investment has less uncertainty compared to offshore.”

[ceo_energemsier + 1,818]

Permian Basin continues to be growth engine of USA onshore hydrocarbon production, says GlobalData

 

Published by Naomi Holliman, Digital Assistant
Oilfield Technology, Thursday, 09 May 2019 12:00

Abundant hydrocarbon reserves and the ability to drill longer laterals has made Permian Basin the most prolific shale play in the world, according to GlobalData, the data and analytics company.

GlobalData’s latest market analysis report, ‘Permian Basin Shale in the US, 2019 – Oil and Gas Shale Market Analysis and Outlook to 2023’, reveals that production of crude oil and natural gas has grown each year from 2013 to 2018 despite the oil and gas industry going through one of the worst downturns during that period.

The Permian Basin is one of the largest structurally developed basins in the US. Shale formations in the Permian Basin can range from 1 300 ft to 1 800 ft in thickness, making it one of the thickest deposits in the world.

GlobalData identifies companies such as Occidental Petroleum, Chevron Corporation, Pioneer Natural Resources, Concho Resources and EOG Resources as among the leading producers in the Permian Basin shale in 2018. The major hydrocarbon producing counties in the Permian Basin include Reeves, Midland, Lea, Loving and Eddy.

As in other unconventional shale plays, operators in the Permian Basin continue to drill longer laterals beyond 9 000 ft with some reaching as much as three miles. The general objective remains to increase the productivity of the new producing wells in a higher proportion with respect to the cost increase associated with these more complex wells.

The Permian has also seen a clear trend for larger scale operations of key operators that increase the surface of continuous acreage and allows for more recovery. This has also driven the M&A activity in the Permian with companies like Chevron, Diamondback Energy and Concho Resources looking to expand their Permian footprint to drive greater efficiency and lower production cost.

Adrian Lara, senior oil and gas analyst at GlobalData, comments: “Permian crude oil production increased by more than 1 million barrels per day (bpd) in 2018, and by early 2019 it has already surpassed the 4 million bpd mark. However, the story for natural gas production is somewhat different, largely because an increasing volume of associated gas has been flared due to limitations in the pipeline capacity. If the capacity constraints persist longer, it may force some operators to shut in their wells.”

The limitations to gas pipeline capacity that gave rise to flaring is estimated to ease during 2019–2020, with approximately 4 billion ft³ of pipeline capacity expected to be added during these two years, giving further lift to Permian production.

Lara concludes, “In spite of the infrastructure bottlenecks, Permian acreage remains highly attractive. Whenever possible, operators try to increase the surface of continuous acreage that would allow for larger scale developments and longer well laterals. This is in fact one of the key drivers behind the recent offers made by both Chevron and Occidental Petroleum to acquire Anadarko’s acreage. Whichever company ends up winning the deal will certainly establish a leading position among the top players in the play.”

[ceo_energemsier + 1,818]

Rystad Energy predicts over 1 million km of oil and gas wells to be drilled over next five years

 

Published by Nicholas Woodroof, Assistant Editor
Oilfield Technology, Monday, 29 April 2019 16:00

 

A study by Rystad Energy is forecasting that more than 1 million km of new oil and gas wells will be drilled over the next five years.

The collective depth of these wells is the equivalent of 25 times around the equator – or 2.5 times the distance to the moon.

As the global oil and gas industry gets back into high gear – thanks in no small part to higher commodity prices – demand for steel is set to increase. This is tied to the rising need for steel casing that is commonly used in oil and gas wells to prevent them from collapsing or getting damaged.

Drawing on its proprietary WellCube database, Rystad Energy forecasts that the number of onshore and offshore oil and gas wells drilled globally will increase to around 65 000 in 2019. Activity levels are then projected to remain around this level through 2023.

“North America will be in a league of its own thanks to the shale boom. Nearly six in ten new wells on the continent will be drilled in shale basins. These wells are typically longer than other supply segment wells. This helps explain why shale wells represent around 80% of the distance drilled in North America by 2023,” said Erik Reiso, Head of Consulting at Rystad Energy.

The study also reveals striking differences between the onshore and offshore markets for new wells.

“Whereas the top four offshore operators will add a quarter of new offshore wells going forward, the top ten in the onshore market only represent around one-third of new wells from 2019 to 2023, implying a much more diversified player landscape,” Reiso added.

[ceo_energemsier + 1,818]

N. American Shale Oil Second Cheapest Oil Source

 

North American shale oil has become the second cheapest source of new oil volumes, according to research by Rystad Energy.

In its latest cost of supply curve update, the energy research firm found that tight oil – such as onshore shale oil in the U.S. – experienced a turnaround in recent years.

North American shale has gone from being ranked the second most expensive resource in 2015 to the second cheapest – following closely behind the Middle East onshore market at No.1.

“As the majors are struggling to replace conventional liquids, a wealthy source of additional resources is tight oil,” said Espen Erlingsen, head of upstream research at Rystad Energy.

The average Brent breakeven price for shale oil is $46 per barrel, just four dollars behind the massive onshore fields in Saudi Arabia and other Middle Eastern countries.

And Rystad estimates that total recoverable resources from North American shale oil have more than tripled since 2014.

“The North American tight oil industry has changed considerably since 2014, as it has proven to be a competitive supply source in a low-price environment,” Erlingsen said. “While costs for tight oil have been reduced, the resource potential has grown considerably over the last four years.”

Another benefit to shale oil is that it typically requires two to four years to recover costs, while offshore normally needs seven to 12 years.

“Tight oil is a short-cycle investment with a relatively brief lead time from the sanctioning of new wells to the start of production. This gives E&P companies the flexibility to adapt to market conditions and easily change activity levels,” Erlingsen said. “In the ever-changing oil price environment, this implies tight oil investment has less uncertainty compared to offshore.”

[Enthalpic + 1,496]

On 5/6/2019 at 11:03 AM, Falcon said:

Warren Buffet wants a piece of the Permian.  He's never been a very smart investor. Yea.

 

Around these parts he would be called a libtard despite the fact he could buy trump about 30 times over (90 billion versus about 3).

[Ian Austin + 131]

On 5/6/2019 at 4:51 PM, Falcon said:

Sorry for your loss. A one needs more than a checkbook to make it in the shale business going forward.   As I stated most of the foolish money that thought oil would sell for $100+ forever were wrong and gone (or will be gone). 

WTI was selling @ $42 at Christmas.  Just exposed the vulnerability of the cowboys running around the basins drilling quicky "good enough wells".  Won't cut it anymore.

The latest advancements have just come into use on last year or so. 

Hess said new wells drilled 2018 55% return at $50 oil. In 2017 only 15%.

Occidental said they had 40 rigs working.  This year producing more oil with 16 rigs. 

Things change.  Technology continues to improve.  It's just not the small or mid independents that haven't implemented new practices and technology.  Look at Anadarko, a very large independent .

Some ask why haven't more independent been acquired.  My guess, the big boys believe the prices/margins will be squeezed again. Each rebound cucle delivers lower highs.  Anadarko was cheap due to poor performance.  Others could go lower before taken out.

Any open unbiased thinking man can see what's coming.

Timing, that's anyone's guess.

Can somebody actually explain said “new technology”? Or is this all a parrot of what’s being read in MSM?

No stupid downtalk, some actual explanation of he Tech, as well as it’s effect on the businesses ability to make $....

[ceo_energemsier + 1,818]

2018 was likely the most profitable year for U.S. oil producers since 2013

Net income for 43 U.S. oil producers totaled $28 billion in 2018, a five-year high. Based on net income, 2018 was the most profitable year for these U.S. oil producers since 2013, despite crude oil prices that were lower in 2018 than in 2013 on an annual average basis.

Lower production costs per barrel of oil equivalent (BOE) and increased production levels contributed to a higher return on equity for these companies for the fourth quarter of 2018 than in any quarter from 2013 through 2018.

The companies included in the analysis are listed on U.S. stock exchanges, and as public companies, they must submit financial reports to the U.S. Securities and Exchange Commission. EIA calculates that these companies accounted for about one-third of total U.S. crude oil and natural gas liquids production in the fourth quarter of 2018. However, these companies were not selected as a statistically representative sample but instead because their results are publically available. Their results do not necessarily represent the U.S. oil production industry as a whole.

Source: U.S. Energy Information Administration, based on Evaluate Energy

Most of these companies operate in Lower 48 U.S. onshore basins, with some in the Federal Offshore Gulf of Mexico and Alaska, and some in several other regions across the globe. Because of various corporate mergers and acquisitions in 2018, the number of U.S. producers that EIA examined in this analysis fell from 46 companies in 2017 to 43 companies in 2018.

The aggregated income statements for these 43 companies reveal a trend of relatively low increases in expenses directly related to upstream production in 2018. Although these upstream production expenses per barrel typically correlate with crude oil prices, the magnitude of these increases in 2018 was small compared with the increase in prices.

The annual average West Texas Intermediate (WTI) crude oil price increased 28% from 2017 to average $65 per barrel (b) in 2018, but expenses directly related to upstream production activities increased 16% between 2017 and 2018 to $24/BOE. When including depreciation, impairments, and other costs not directly related to upstream production, expenses for these 43 companies averaged $48/BOE in 2018, the lowest amount from 2013 to 2018.

In contrast to production expenses, between 2017 and 2018, upstream revenue for these 43 companies increased 31% to average $48/BOE in 2018, mainly because of the increases in average energy prices and production. As crude oil prices fell in late 2018, their upstream revenue declined 11% between the third and fourth quarters of 2018.

Source: U.S. Energy Information Administration, based on Evaluate Energy

However, this group of companies reported financially hedging nearly one-third of their fourth-quarter 2018 production at prices in the mid-$50/b range, offsetting revenue declines when WTI prices fell lower than $50/b by the end of the year. Consequently, even with their decline in upstream revenue in the last quarter of 2018, total revenue increased for these 43 companies because of the gains from financial derivatives.

Contributions to revenue from derivative hedges—which increase in value when prices decline—for these 43 companies reached the largest total for any quarter since the fourth quarter of 2014. Financial hedging can act like an insurance policy, reducing risk by stabilizing revenue for producers. When oil prices fall lower than the prices at which producers established a hedge, the producer effectively receives higher revenues than selling at market prices. When oil prices rise higher than the hedged price, hedging results in a loss that is treated as an operating expense.
Source: EIA

[ceo_energemsier + 1,818]

U.S. exploration and production companies (E&Ps) are tapping the brakes on their capital spending in 2019 after two years of strong investment growth and a return to profitability that in 2018 approached the level generated in the $100+/bbl crude oil price environment back in 2014. The pull-back in capex this year appears likely to slow the pace of production growth, and comes despite a 30% rebound in crude oil prices in the first quarter of 2019. What’s going on? Well, many investors remain skeptical about E&Ps, as evidenced by stock prices that remain in the doldrums, and to gain favor with investors, a number of E&Ps are returning cash to them in the form of share buybacks and higher dividends. Today, we consider the current state of investment in the E&P sector, how it’s affected by stock valuations and how it affects production growth.

In a number of blogs over the past three years, we’ve documented the dramatic recovery of the E&P sector from the financial crisis caused by the plunge in oil prices that began in late 2014. Through portfolio high-grading and an intense focus on operational efficiency, the 44 representative E&Ps we track demonstrated that they could grow reserves and increase production on lower capital budgets. The nearly 50% reduction in “finding and development” costs (the cost of “finding” an additional barrel through organic capital spending), excluding acquisitions — from $15.01/boe (barrel of oil equivalent) in 2014 to $8.41/boe in 2018 — helped the E&P sector roar back to profitability last year. Our universe of 44 E&Ps on average netted a healthy pre-tax operating profit of $11.03/boe in 2018, which compares with a barely breakeven profit of $0.07/boe in 2017 and is only 20% below the profit generated by the group in the $100+/bbl environment in 2014. And with first-quarter 2019 oil prices rising 30% — the largest quarterly rise since 2009 — the E&P sector appears to be in a position to report continued profit growth this year.

 

E&P share prices by December 2018 had plunged 40% from their September highs when crude prices slid to $45/bbl, and despite the subsequent oil price rebound, share prices have recovered less than half of their late-2018 declines.

Several oil companies released slimmed-down 2019 capital budgets in late 2018, when oil prices were still sagging. Many industry observers assumed the planned declines in investment reflected conservatism about the oil pricing outlook going forward. The oil price decline turned out to be short-lived, however, with prices recovering strongly starting in late December 2018 and through the first quarter of 2019. Still, updated capex plans released with year-end 2018 results in late January and February continued to mirror the overall trend, and almost no companies moved to revise their budgets upward. (Guidance updates released so far with first-quarter results in late April and early May do not indicate any significant changes from year-end forecasts.)

Figure 1 shows that capital spending for our universe of 44 E&Ps (blue bars, left axis) totaled $135 billion in 2014, but was cut by more than $50 billion in 2015, then slashed in half in 2016 to $40 billion. In 2017, capital outlays rebounded with commodity prices, increasing by about 50% to about $63 billion, and rose by another $15 billion or so in 2018. This $77 billion in 2018 investment generated a 26% increase in pre-tax operating cash flow to $112 billion last year (orange bar to right; left axis) and a 7% increase in production (gray line; right axis). Historically, the higher cash flow would have led to continuing capital investment increases in 2019.  However,  as shown in Figure 1, the companies in our universe announced a collective 12% retrenchment in capital outlays this year. Three-quarters of the 44 E&Ps we track will cut capital spending in 2019, with a median decline of 15%.

Figure 1. E&Ps’ Cash Flow, Capital Spending and Production, 2014-19. Source: Oil & Gas Financial Analytics, LLC (Click to Enlarge)

So, what gives? The E&Ps’ year-end results revealed a major driver of the lower capital budgets: a significant boost in the amount of cash flow being returned to shareholders, primarily through share repurchases. The buyback programs of our group of 44 E&Ps — which are designed to appeal to investors — soared from $4.7 billion in 2017 to $15.6 billion in 2018, while dividends increased 17% to $6.7 billion.

The reduced 2019 capital spending will have an impact on oil and gas output. The surge in investment over the past couple of years drove a substantial 7% increase in production in 2018, including a 13% increase by our Oil-Weighted Peer Group. 2019 guidance indicates oil and gas production growth by our 44 E&Ps will moderate to only 5% this year, or a 200-MMboe rise to 4.7 billion boe. Capital allocation across producing regions in 2019 remains virtually the same as in 2018. The Permian Basin will see the lion’s share of capital investment this year, at 42% of total capital spending. The Eagle Ford Shale is a distant second at 11% of 2019 capex, with the remaining capital investment spread among the Bakken (9%), the Marcellus (8%), International (8%), SCOOP/STACK (6%), the Denver-Julesburg (D-J) Basin (5%), the Utica (2.5%), and the offshore Gulf of Mexico (2%). Next, we review 2019 capital spending and the impact on production by peer group.

Oil-Weighted E&Ps

Figure 2 shows that the 18 E&Ps in the Oil-Weighted Peer Group collectively reduced their 2019 capital budgets by 12%, or $4 billion, to just under $30 billion (blue bar to far right; left axis) despite generating $19 billion in pre-tax operating profit and $45 billion in cash flow in 2018 (orange bar to right; left axis). Capital outlays peaked in 2014 at $47 billion (blue bar to far left), and were slashed by $19 billion in 2015 and by an additional 45% in 2016 to $15.6 billion. In 2017-18, capital spending rebounded along with oil prices, increasing by 60% (to $25 billion) in 2017 and by another 34% (to $34 billion) in 2018. The oil-weighted E&Ps spent $5 billion on share repurchases last year, $3.8 billion more than they did in 2017 and 23% more than in 2014. Dividends paid in 2018 by the oil-focused E&Ps reached $3.6 billion in 2018, 20% higher than in 2017 and on par with 2014 payouts.

 

 

 

Finding and development costs for the oil-weighted E&Ps have fallen from more than $21/boe in 2014 to $12.72/boe in 2018. This allowed the producers to generate 13% production growth in 2018 (gray line, right axis) despite investment that was 30% lower than in 2014. Output growth is expected to slow to 7%, or about 100 MMboe, in 2019. Over 60% of the capital invested by the Oil-Weighted Peer Group this year will be spent in the Permian Basin, in line with the 2018 capital allocation, while 13% will be invested in the Eagle Ford (2% ahead of last year), 9% will be spent in the Bakken and 6% will be spent in the D-J Basin

Oil-Weighted E&Ps' 2018 Profits, Cash Flow, Upstream Spending and Capital Returned to Shareholders

Wednesday, 05/08/2019Published by: jeremy

 

 

 

 

 

Diversified E&Ps

Figure 3 shows that the 16 E&Ps in the Diversified Peer Group are collectively forecasting an 11% decline in capital investment to $29 billion in 2019 (blue bar to far right; left axis) despite generating more than $50 billion in cash flow in 2018 (orange bar to right; left axis). Capital spending for the Diversified E&Ps peaked at $70 billion in 2014 (blue bar to far left), and was slashed by nearly three-quarters by 2016 to $18 billion — the companies were undergoing earth-shattering changes to become profitable in a low oil and gas price environment. These changes included more than 3 billion boe in asset sales in order to reposition themselves by divesting non-core assets. In 2016, capital investment started to rebound, increasing by nearly $9 billion in 2017 and then adding another $6 billion in capital outlays in 2018. A portion of the $21 billion in free cash flow last year was used to increase payout to investors. In 2018, the Diversified E&Ps repurchased nearly $8.4 billion in common shares, nearly three times the amount bought in 2017. Dividend payments last year increased modestly to $2.7 billion, but that was still about 50% lower than what was paid out in 2014 as companies clearly have a preference for opportunistic share repurchases.  

 

Fueling the rise in free cash flow has been a sharp reduction in finding and development costs, which has enabled companies to lighten up their capital commitments while still maintaining reserve and production levels. Finding and development costs have been cut by more than half, from nearly $24/boe in 2014 to $9.24/boe in 2018. While the Diversified Peer Group’s production (gray line, right axis) has been hampered in recent years by the large divestment of assets, the downtrend appears ready to make a turnaround. In 2018, production posted its first increase since 2015, growing nearly 2% in 2018 to 1.8 billion boe, and it is expected to grow another 4.5% in 2019 to nearly 1.9 billion boe.  

About 40% of the Diversified E&Ps’ capital budgets will be invested in the Permian Basin, with 16% allocated outside of the U.S. The Bakken will absorb another 13%, compared with 9% last year. The SCOOP/STACK and Eagle Ford are each taking on 10% of peer group capex, similar to last year’s capital allocation.

 

Gas-Weighted E&Ps

Capital investment for the 10 E&Ps in the Gas-Weighted Peer Group has followed a slightly different trend than the rest of our E&P universe. Capital spending by these gas-focused companies peaked in 2014 at just over $17 billion (blue bar to far left in Figure 4; left axis) and subsequently fell by more than 60% to its 2016 bottom of $6.7 billion. Capex rebounded in 2017 by nearly 90% to $11 billion, but stagnated in 2018 before an expected 16% decline this year.  

The gas-weighted E&Ps have also reduced capital costs, but not to the same extent as the other peer groups. Finding and development costs fell by only about 20% between the $4.52/boe posted in 2014 and the $3.75/boe reported in 2018. Nevertheless, free cash flow has increased sharply over the past few years, as have share repurchases, which are up seven-fold to $2.2 billion in 2018 — multiples of what was repurchased in the 2014-17 period. Dividends in 2018 amounted to $306 million, nearly 20% higher than in 2017, but still well below the 2014 payouts. As shown in Figure 4, production for the Gas-Weighted Peer Group has risen steadily, from 819 MMboe in 2014 to 1.261 billion boe in 2018, a compounded annual growth rate of 9.5%. The rate of change is expected to slow precipitously in 2019, to only 1.8%, resulting in 2019 production of 1.284 billion boe.

Figure 4. Gas-Weighted E&Ps’ Cash Flow, Capital Spending and Production 2014-19. Source: Oil & Gas Financial Analytics, LLC (Click to Enlarge)

Three-quarters of the gas-weighted E&Ps’ 2019 investment will target Appalachia (60% Marcellus, 15% Utica), which is on par with 2018. An additional 7% is being invested in the Eagle Ford and another 4% being deployed in SCOOP/STACK.

While crude oil prices got off to a slow start in 2019, the ensuing rally looks like it will push E&Ps’ first-quarter 2019 profits to exceed fourth-quarter 2018 results and set the stage for a strong 2019 as a whole.  We will continue to monitor E&P announcements and will provide an update at mid-year to highlight any changes in capital spending, production and capital allocation trends we spot. 

[Falcon + 222]

On 5/10/2019 at 2:34 AM, Ian Austin said:

Can somebody actually explain said “new technology”? Or is this all a parrot of what’s being read in MSM?

No stupid downtalk, some actual explanation of he Tech, as well as it’s effect on the businesses ability to make $....

Explain new technology ? How about reading CV's 20 posts on this thread .

Please

LOL

[Ian Austin + 131]

54 minutes ago, Falcon said:

Explain new technology ? How about reading CV's 20 posts on this thread .

Please

LOL

You did a wonderful job of not answering the question LOL. 

And copying/pasting articles doesn’t tell me anything other than you know how to Google search.

This forum is going to s$$t, in record time...

[Mike Shellman + 548]

1 hour ago, Falcon said:

Explain new technology ? How about reading CV's 20 posts on this thread .

Please

LOL 

Mr. Austin is a Petroleum Engineer; his question is valid and posting lengthy articles, in their entirety, multiple times, that have been cherry picked, don't answer the question at all. A good answer would be based on personal analysis, work,  researched data and actual evidence. All the articles posted were written by the shale oil industry itself and/or people who service the shale oil industry with data-sell and benefit from promoting it. There are a number of analyses in the public realm that are NOT very flattering about shale oil economics and the direction that faction of the oil industry is headed. Those, of course, get skipped over. Well productivity is declining, all shale oil basins save the Delaware appear to be getting gassier and flaring, accordingly, is getting worse. BOE is worthless metric. The RBN stuff was for 2018; based on SEC filings 1Q19 was pretty lousy for the entire shale oil industry save perhaps EOG and COP. 

Laughing out loud at someone on a public forum is designed to be insulting. Its easy to do from the comfort of your home and keyboard, particularly when you don't have the cajones to even use your own name. Using social media to boast about how much free royalty you make, or how many VLCC's you have, hardly qualifies you  as "expert" on anything. Insulting someone because they don't agree with you does, however, qualify you as having the manners of a goat.  

I agree with Mr. Austin, this forum has gone to shit in record time and it is pretty clear why. Several are trying to dissuade rational debate and are trying to control its content. 

 

Edited May 13, 2019 by Mike Shellman

[ceo_energemsier + 1,818]

Yes this forum is going to total schitt, when a very select few , instead of actually having a discussion and bringing forth facts about something resort to name calling and denigrating others opinions because they have a certain agenda. It is evident that the people calling for rational debate are the first ones to denounce and put down and discredit any info or data that does not fit their narrative.

The EIA data is here also for 2018, as 2019 hasnt ended yet!

https://www.eia.gov/todayinenergy/detail.php?id=39413

Oh yes, I am copying and pasting some key takeaways from the EIA statement.

"Net income for 43 U.S. oil producers totaled $28 billion in 2018, a five-year high. Based on net income, 2018 was the most profitable year for these U.S. oil producers since 2013, despite crude oil prices that were lower in 2018 than in 2013 on an annual average basis.

Lower production costs per barrel of oil equivalent (BOE) and increased production levels contributed to a higher return on equity for these companies for the fourth quarter of 2018 than in any quarter from 2013 through 2018.

The companies included in the analysis are listed on U.S. stock exchanges, and as public companies, they must submit financial reports to the U.S. Securities and Exchange Commission. EIA calculates that these companies accounted for about one-third of total U.S. crude oil and natural gas liquids production in the fourth quarter of 2018. However, these companies were not selected as a statistically representative sample but instead because their results are publically available. Their results do not necessarily represent the U.S. oil production industry as a whole.

Most of these companies operate in Lower 48 U.S. onshore basins, with some in the Federal Offshore Gulf of Mexico and Alaska, and some in several other regions across the globe. Because of various corporate mergers and acquisitions in 2018, the number of U.S. producers that EIA examined in this analysis fell from 46 companies in 2017 to 43 companies in 2018.

The aggregated income statements for these 43 companies reveal a trend of relatively low increases in expenses directly related to upstream production in 2018. Although these upstream production expenses per barrel typically correlate with crude oil prices, the magnitude of these increases in 2018 was small compared with the increase in prices.

The annual average West Texas Intermediate (WTI) crude oil price increased 28% from 2017 to average $65 per barrel (b) in 2018, but expenses directly related to upstream production activities increased 16% between 2017 and 2018 to $24/BOE. When including depreciation, impairments, and other costs not directly related to upstream production, expenses for these 43 companies averaged $48/BOE in 2018, the lowest amount from 2013 to 2018.

In contrast to production expenses, between 2017 and 2018, upstream revenue for these 43 companies increased 31% to average $48/BOE in 2018, mainly because of the increases in average energy prices and production. As crude oil prices fell in late 2018, their upstream revenue declined 11% between the third and fourth quarters of 2018."

I guess some folks will be happy only if the shale industry folds up and vanishes, perhaps reducing or removing competition to their own vested interests and propping up their own sector of the industry.

 

 

🍾

 

[Ian Austin + 131]

5 hours ago, ceo_energemsier said:

Yes this forum is going to total schitt, when a very select few , instead of actually having a discussion and bringing forth facts about something resort to name calling and denigrating others opinions because they have a certain agenda. It is evident that the people calling for rational debate are the first ones to denounce and put down and discredit any info or data that does not fit their narrative.

The EIA data is here also for 2018, as 2019 hasnt ended yet!

https://www.eia.gov/todayinenergy/detail.php?id=39413

Oh yes, I am copying and pasting some key takeaways from the EIA statement.

"Net income for 43 U.S. oil producers totaled $28 billion in 2018, a five-year high. Based on net income, 2018 was the most profitable year for these U.S. oil producers since 2013, despite crude oil prices that were lower in 2018 than in 2013 on an annual average basis.

Lower production costs per barrel of oil equivalent (BOE) and increased production levels contributed to a higher return on equity for these companies for the fourth quarter of 2018 than in any quarter from 2013 through 2018.

The companies included in the analysis are listed on U.S. stock exchanges, and as public companies, they must submit financial reports to the U.S. Securities and Exchange Commission. EIA calculates that these companies accounted for about one-third of total U.S. crude oil and natural gas liquids production in the fourth quarter of 2018. However, these companies were not selected as a statistically representative sample but instead because their results are publically available. Their results do not necessarily represent the U.S. oil production industry as a whole.

Most of these companies operate in Lower 48 U.S. onshore basins, with some in the Federal Offshore Gulf of Mexico and Alaska, and some in several other regions across the globe. Because of various corporate mergers and acquisitions in 2018, the number of U.S. producers that EIA examined in this analysis fell from 46 companies in 2017 to 43 companies in 2018.

The aggregated income statements for these 43 companies reveal a trend of relatively low increases in expenses directly related to upstream production in 2018. Although these upstream production expenses per barrel typically correlate with crude oil prices, the magnitude of these increases in 2018 was small compared with the increase in prices.

The annual average West Texas Intermediate (WTI) crude oil price increased 28% from 2017 to average $65 per barrel (b) in 2018, but expenses directly related to upstream production activities increased 16% between 2017 and 2018 to $24/BOE. When including depreciation, impairments, and other costs not directly related to upstream production, expenses for these 43 companies averaged $48/BOE in 2018, the lowest amount from 2013 to 2018.

In contrast to production expenses, between 2017 and 2018, upstream revenue for these 43 companies increased 31% to average $48/BOE in 2018, mainly because of the increases in average energy prices and production. As crude oil prices fell in late 2018, their upstream revenue declined 11% between the third and fourth quarters of 2018."

I guess some folks will be happy only if the shale industry folds up and vanishes, perhaps reducing or removing competition to their own vested interests and propping up their own sector of the industry.

 

 

🍾

 

I think it’s time to bow out, given anybody’s reluctance to actually answer a GD question. 

Enjoy it while it lasts 

[footeab@yahoo.com + 2,192]

32 minutes ago, Ian Austin said:

I think it’s time to bow out, given anybody’s reluctance to actually answer a GD question. 

Enjoy it while it lasts 

I take it you are a layman or outsider looking into the oil industry who is looking to invest a large chunk of change?  Here is the simplified version minus charts and BS propaganda.

All the tech being quoted, 3D seismic, multi lateral drilling off single well bore, multi pad well drilling, differential fracking, etc has been around.... selectively, in niches of the oil market before ~2010 or even 2000.  It takes a LONG while for any industry to switch over to not only buy upfront, install(downtime), and start using these new methods, but to get GOOD at using them(knowledge & logistics).  That is all before one even talks about becoming ECONOMICAL at cost cutting using these new methods/tools while still achieving good results.  What we see today, is NOT new tech, but rather ~decade old or even 2+ decade old tech which has finally become mature by combining the niche older tech into a holistic soup of MUCH lower costs. 

[Ian Austin + 131]

2 minutes ago, Wastral said:

I take it you are a layman or outsider looking into the oil industry who is looking to invest a large chunk of change?  Here is the simplified version minus charts and BS propaganda.

All the tech being quoted, 3D seismic, multi lateral drilling off single well bore, multi pad well drilling, differential fracking, etc has been around.... selectively, in niches of the oil market before ~2010 or even 2000.  It takes a LONG while for any industry to switch over to not only buy upfront, install(downtime), and start using these new methods, but to get GOOD at using them(knowledge & logistics).  That is all before one even talks about becoming ECONOMICAL at cost cutting using these new methods/tools while still achieving good results.  What we see today, is NOT new tech, but rather ~decade old or even 2+ decade old tech which has finally become mature by combining the niche older tech into a holistic soup of MUCH lower costs. 

Actually I have quite a bit of experience in the industry, in Wellbore Construction (probably one of a handful who has actually done all of what you mentioned in he comments above, save the Seismic interpretation (all squiggly lines to me, although I realize the skill and it importance) and have been quoted here saying pretty much what you just said. There is some impressive combining/re-purposing going on in industry. Calling it new technology both does a disservice to real new tech and is uninformed  

I’m slightly annoyed with a small fraction of this board, who post long winded articles under the guise of actual knowledge. Somebody mentioned something about all of the new tech. As somebody who has worked with said technology, I asked what was new and exciting. Of course, you’d think I asked for a kidney by the answers. 

This used to be a fun place to talk business and tech. Now it’s overrun by 3-4 blowhards, who have little-no knowledge (outside of a knack for Google Search) flood the forums with junk and generally piss everybody else off.

This place is turning into a “he who screams loudest, wins” type of place. 

I do sincerely thank you though for actually answering a question, instead of spamming his message board. 

[BillKidd + 139]

I saw this very thing happen to another forum... a certain blowhard poster monopolizing the forum, posting countless LONG articles to "prove" his point. It drove everyone insane and the moderators refused to ban him for the longest time. Finally, after many complaints, they did, in fact ban him and it survived, although its membership never recovered from the exodus of a lot of good people due to the blowhard poster. One guy ruined it. Well, lack of action by moderators ruined it.