Wonders of US Shale: US Shale Benefits: The U.S. leads global petroleum and natural gas production with record growth in 2018

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North Dakota drillers set oil production record in August

 

 

https://apnews.com/996cbf8df17744798bc59f3d51199915

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US Crude Exports Expected to Double by 2022

 

 

The U.S. could see its crude oil exports nearly double by 2022, according to energy research firm Rystad Energy.

Rystad forecasts that U.S. crude exports could increase from current levels of 2.9 million barrels per day (bpd) to nearly six million bpd by 2022. This is based off the nation’s expected production increase of 1.2 million bpd year-over-year in 2020 and domestic refineries at capacity to absorb shale growth.

“Crude exports will grow on the back of new infrastructure coming online in Corpus Christi, Texas, and as international crude buyers ramp up efforts to diversify their import sources after the attacks on oil facilities in Saudi Arabia and overall rising tensions in the Middle East,” said Paola Rodriguez-Masiu, a senior analyst on Rystad’s oil market team.

Rystad also noted the recent slowdown of U.S. crude exports in third quarter of 2019, due in part to the narrowing of the Brent-WTI price spread and effects from the five percent tariff imposed on U.S. crude by China.

Despite that slowdown, Rystad expects an export rebound to 3.7 million bpd in fourth quarter 2019 before climbing to even higher levels.

“This surge in crude shipments from the U.S. will be made possible by a flurry of new pipeline and export terminal infrastructure coming online in the coming years,” Rodriguez-Masiu said

 

 

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Kinder Morgan’s Elba LNG plant is finally starting up, with one train producing and two more on the way.

The first unit was placed into service at the end of September, with start-up work under way on the second and third units. Commissioning is taking place on the fourth, fifth and sixth units and construction on the remaining four “largely complete”, the company said in its third quarter results. The facility is near Savannah, in Georgia.

Total capacity at the plant will be 2.5 million tonnes per year, equivalent to around 350 million cubic feet (9.9 million cubic metres) per day of gas. Production from the $2.1 billion Elba LNG is contracted to Shell, for a 20-year term. The 10 trains were constructed on the basis of the Movable Modular Liquefaction System (MMLS), using Shell technology.

Kinder Morgan owns Elba LNG via a joint venture, in which it has a 51% stake, with EIG Global Energy Partners. Starting up the first unit has let Kinder Morgan earn around 70% of its expected total daily revenue from the units.

The Elba Island facility was previously an import terminal, but only received LNG shipments from 1978 to 1980. Shell had owned EIG’s 49% stake until July 2015, when it sold this equity to Kinder Morgan. In the statement announcing the sale of Shell’s stake, the companies said Elba LNG was expected to start producing in late 2017.

Kinder Morgan also expressed its bullish sentiments about the future of natural gas in the US in its third quarter results, which would be partly driven by LNG exports.

Kinder Morgan said it expected gas demand – including LNG exports and pipeline exports to Mexico – in the US would increase by 34% from 2018 levels, to more than 120 billion cubic feet (3.39 mcm) per day. LNG exports will show the greatest increase, up by more than five-fold, it said. Exports to Mexico will also rise substantially, up by 57%.

Construction on the plant was carried out by IHI E&C, under an engineering, procurement, construction and commissioning (EPCC) contract announced in April 2016.

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Companies Opting For Shorter Cycle Times As Conventional Projects Decline

Recent IHS Markit report says a significant rebound in discoveries may not happen because since 2014 there has been an increased emphasis on exploring less risky maturing basins and short cycle-time unconventional projects.

 

As the way the world consumes energy shifts more and more, there is a growing concern from investors about just how much of a demand there will be for conventional oil and gas in the future.

That is one of the realities that may be causing conventional oil and gas discoveries to sink to their lowest levels in seven decades according to a new report released earlier this month by IHS Markit. The overwhelming reason for the downturn in discoveries is declining prices, the report said, but there is at least some concern about what energy consumption may look like as renewables become a bigger part of the world’s energy mix.

The report, titled “IHS Markit Conventional Exploration Results in Early 2018 Through 2019: No Rebound in Activity or Results,” said a significant rebound in discoveries may not happen. That’s because since 2014 there has been an increased emphasis on exploring less risky maturing basins and short cycle-time unconventional projects.

Companies are placing an emphasis on smaller basins in which they can cut cycle time from 10 years to three years to even a year. The average discovery size of these early lifecycle basins is approximately 210 million barrels (MMbbl) versus 25 MMbbl from mature basins discovered during the last 10 years.

“If you see all of these projections of demand starting in the 2030s or some cases the 2020s because everyone is going to go to renewables and I won’t need oil and gas after 2025 or 2030,” said IHS senior advisor Keith King, who is also a lead author of the IHS Markit E&P trends analysis, in an interview with HartEnergy.com. “That’s more on the liquefied gas.

“So the thought process is why go out and drill an expensive wildcat in a frontier basin that it takes five years to appraise if it’s successful and four years to get it approved for development and then takes 10 years to develop. The demand for production can start to decline by the time it gets going. So it seems better to go after shorter cycle opportunities.”

The de-emphasis on new discoveries due to alternate energy sources and declining interest by investors in taking financial risks along with the declining global prices have played a role in the drop in discoveries.

“All of that kind of sticks together, no one articulates it quite that way,” King said. “But to think about it, it makes sense. Why would I invest in something that isn’t going to be producing in 20 to 40 years the demand may not be there?

“The other thing is the understanding about the demand structure versus in investment. If you are concerned about interest rates going forward you buy shorter term bonds.

“People are also starting to invest more in renewables, not a significant amount but they are starting to say I’ll build some wind farms and do some of these other things,” King continued. “This is the first time in the 40 years I’ve been in this business that we have had such an existential threat from another source of energy like wind and solar. Before, after the 2009 turn, after the downturn in 1999 and 1980 and 1986 we all knew what we were going to do when the price recovered but now it’s not as clear cut.”

King does leave open the possibility of a rebound in discoveries, it just may not come back in the same robust way as did after past downturns. He said the key is understanding why discoveries aren’t rebounding right now.

Concerns about constraining carbon and slowing climate change have become a game changer in the industry and King says those concerns will cause people to second-guess oil in the next 20 to 25 years.

“If those things go away or one day we wake up and say solar and wind can’t provide our energy we need to have oil and gas production, if that changes then I think you will start to see an increase in conventional exploration,” he said.

 

 

[James Regan + 1,776]

On 10/15/2019 at 5:46 AM, Auson said:

Ha ha Brilliant I wondered if you would get that, The Beat and the Selecter great bands I used to like all the old stuff from the 60s too.

Do I remember you saying you held Premier Oil, have you heard any whispers re Zama or Sealion recently ?

Purple Hearts, Secret Affair etc, good days....

I don't hold any Oil stocks, I'm not stupid, definitely not stupid enough to buy any LTO stock, They call it Madness, one step beyond.......

Edited October 20, 2019 by James Regan

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US petroleum demand highest on record for September

Although geopolitics and trade tensions continued to rankle global oil markets in September, the US market remained relatively insulated, according to the latest monthly statistical report from the American Petroleum Institute.

 

 

Although geopolitics and trade tensions continued to rankle global oil markets in September, the US market remained relatively insulated, according to the latest monthly statistical report from the American Petroleum Institute.

First, US domestic petroleum demand, as measured by total domestic deliveries, was 20.8 million b/d—its highest level on record for the month of September. This was a seasonal decrease of 3.2% from August but an increase of 3.5% compared with September 2018. Year-to-date through September, total petroleum demand averaged 20.5 million b/d, up 0.3% year over year and the strongest level since 2007.

Consumer gasoline demand, measured by total motor gasoline deliveries, was 9.3 million b/d in September. This represented a seasonal decrease of 5% from August but was up by 1.3% compared with September 2018. Year-to-date through September, however, gasoline demand decreased by 0.4% year-over-year.

In September, distillate deliveries of 3.9 million b/d decreased by 1% from August and 3.2% compared with September 2018. Cumulatively through September, distillate deliveries decreased 1.6% year-over-year.

 

Kerosene jet fuel demand at 1.7 million b/d in September fell below its 2018 levels for only the second time so far this year. This was a decrease of 1.9% compared with September 2018 and 11.3% below August—the largest seasonal decrease for September since 2001 and the Sept. 11 attacks on New York and Washington. The International Air Transport Association has not yet reported data for September but suggested in its Oct. 9 report that the US-China trade war has weighted heavily on air cargo with trade volumes down 1% year-over-year in September.

Residual fuel oil deliveries were 365,000 b/d in September, which was an increase of 2% from August and 4.6% compared with September 2018. This also was the highest level so far this year, just months in advance of tighter marine fuel sulfur specifications taking effect in January 2020.

Refining and petrochemical deliveries of liquid feedstocks, naphtha, and gas oil were at their highest ever in September at 5.7 million b/d. This was an increase of 1.1% from August and the highest monthly level on record.

Supply, trade

In September, the US recorded a new record 12.4 million b/d for crude oil production and sustained record natural gas liquids production of 4.8 million b/d. The production records came despite less drilling activity in September.

Baker Hughes Co. reported oil-targeted rigs decreased by 7.2% between July and September. The US Energy Information Administration estimates the backlog of drilled but uncompleted wells declined below 8,000 in August from previously reported peaks above 8,500 wells.

US petroleum exports rose to 8.2 million b/d in September from 8.1 million b/d in August. Meanwhile, imports fell by 1 million b/d between August and September to their lowest level for the month since 1993.

Overall US petroleum net imports decreased to 800,000 b/d in September—the second lowest level this year and a step closer to the US becoming a net exporter.

Refining operations, inventories

In September, gross inputs to US refineries of 17 million b/d implied a capacity utilization rate of 90.2%. These marked notable slowing from August, which had the highest refinery throughput and capacity utilization rates so far this year.

US total petroleum inventories were 1.32 billion bbl for the month, including crude oil and refined products but excluding the Strategic Petroleum Reserve. Inventories increased despite crude oil stocks falling to their lowest level so far this year.

Macroeconomics

API’s Distillate Economic Indicator, which includes industry fundamentals, prices, and interest rates, had a reading of 0 (+0.03) in September and also a 3-month average reading of 0 (-0.03), which historically has corresponded with slowing US industrial production.

The Institute for Supply Management’s Purchasing Managers Index again signaled a contraction of industrial activity in September with a reading of 47.8%. New orders, production, and employment each decreased, while supplier deliveries slowed and indicators covering trade, supplier backlogs, inventories, and raw materials weakened.

 

While leading indicators of industrial activity signaled a slowing through most of this year, consumer sentiment remained optimistic. The University of Michigan’s consumer sentiment index increased to 96 as of early October, up from 93.2 in September but down from 98.6 in August. These readings suggest solid consumer sentiment, and the survey noted household real income expectations have risen to their most favorable level in 2 decades.

 

 

 

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Permian Operators Delivering Strong Production

Permian production continues its market domination

 

 

There are 380 operators active in the Permian Basin, and large and small independents and private-equity companies account for 80% of production, according to a recent Midland Reporter-Telegram article. 

Stratas Advisors reports that strong growth in the Permian will continue to boost U.S. production. “When looking into the data from operators in the Permian (Bone Spring, Spraberry, Wolfcamp Delaware and Wolfcamp Midland) the term ‘bigger is better’ is ringing true. Since the beginning of 2017, the average of the top three quintiles has seen lateral lengths, fluid volumes and proppant volumes increase. This has resulted in peak rates in the Permian to rise 40%,” Whitney Gomila, a senior analyst with Stratas Advisors, told E&P. “Looking ahead to 2020, Stratas expects Permian production to average 8 MMboe/d (~15% YoY), which represents almost 30% of Lower 48 production.”

GlobalData recently reported that the Permian Basin is “the most prolific shale play in the world” and attributes this to its “abundant hydrocarbon reserves and the ability to drill longer laterals.” In the report, GlobalData identified companies such as Occidental Petroleum, Chevron, Pioneer Natural Resources, Concho Resources and EOG Resources as among the leading producers in the Permian Basin shale in 2018.

In the following section, E&P profiles some of the most active Permian operators, providing their recent production updates and strategies moving forward.

 

 

Apache Corp.

Apache’s Permian production averaged 226,000 boe/d during the second quarter, and the company operated an average of 12 rigs and drilled and completed 54 gross operated wells, according to Apache’s second-quarter 2019 results report.

In the Midland Basin, the company averaged four rigs and placed 20 wells on production during the second quarter.

In the Delaware Basin outside of Alpine High, Apache averaged three rigs and placed nine wells on production during the second quarter.

At Alpine High, the company averaged five rigs and two frac crews and placed 26 wells on production during the second quarter, and production was reported at 49,000 boe/d.

“Apache continues to deliver cost reductions in the Delaware Basin with average drilling and completion costs per foot down 26% and 41%, respectively, from 2017 through the end of the second quarter,” according to the report.

“While total Permian production volumes were strong, oil volumes trailed guidance due to timing delays bringing wells online during the quarter. We will catch up in the second half of 2019 and exit the year with oil production on plan and with strong momentum heading into 2020,” Apache CEO and President John J. Christmann IV said in the report.

For Permian Basin oil, Apache expects third-quarter production to be 94,000 boe/d to 98,000 boe/d and fourth-quarter production to be 100,000 boe/d to 105,000 boe/d. At Alpine High, Apache expects third-quarter production to be between 70,000 boe/d to 75,000 boe/d.

In addition, as stated in the report, one of Apache’s second-half 2019 objectives is to increase Permian Basin oil well completions and oil production.

 

 

 

 

BPX Energy, a division of BP

In October 2018, BP Plc changed the name of its Lower 48 business to BPX Energy. “The change marks a new era of growth for BP’s U.S. onshore oil and gas unit, which has operated as a separate entity since 2015,” the company stated on its website. BPX Energy produces primarily natural gas, along with oil, condensate and NGL.

In November 2018, BP completed a $10.5 billion acquisition of BHP Billiton’s unconventional oil and gas assets in the Permian-Delaware Basin in Texas, along with two premium positions in the Eagle Ford and Haynesville shale plays in Texas and Louisiana. At the time of the acquisition, the assets were producing 190,000 boe/d, of which about 45% were liquid hydrocarbons, BPX reported.

In February of this year, Mohit Singh, senior vice president of business development and exploration for BPX Energy, presented at Hart Energy’s DUG Haynesville conference and shared how BP is transforming its U.S. onshore business following that $10.5 billion acquisition last year. Starting March 1, the company took over operations from BHP. “The deal includes assets in the Permian’s Delaware Basin, adding about 41,000 boe/d in production with 3,390 gross drilling locations on an 83,000-acre position,” a HartEnergy.com article stated. By 2021 BPX Energy expects to have 3,500 wells (down from 9,400 in 2018) and operate in only the Delaware, Eagle Ford and Haynesville (down from six basins prior to divestitures), according to the article.

In its second-quarter 2019 results report, BPX Energy reported it had an average of three company-operated rigs in the Permian during the quarter.

 

 

 

Centennial Resource Development Inc.

Centennial Resource Development is an independent oil producer with assets in the Delaware Basin in New Mexico and Texas. The company has about 80,100 net acres (90% operated) and about 2,400 horizontal drilling locations (about 60% oil). 

In the second quarter this year, average crude oil production increased 38% to 43,105 bbl/d of oil compared to the prior year period, and average total equivalent production increased 32% in the second quarter and 33% for the first six months of 2019 compared to prior year periods, according to Centennial’s second-quarter 2019 results press release. As of Aug. 5, Centennial expected to reduce its operated rig count from six to five in September, maintaining a five-rig drilling program for the remainder of the year.

 

 

Chevron

In the Permian Basin, Chevron reported net production of 159,000 bbl/d of crude oil, 501 MMcf/d of natural gas and 66,000 bbl/d of NGL in 2018. “We are among the largest producers of oil and natural gas in the basin, and with approximately 2.2 million net acres, Chevron is one of the Permian Basin’s largest net acreage holders,” the company stated on its website.

Second-quarter 2019 unconventional production in the Permian was 421,000 bbl/d, representing growth of more than 50% compared to a year ago, according to Chevron’s second-quarter 2019 results news release.

Chevron has added almost 7 Bbbl of resource and doubled its portfolio value over the past two years in the Permian Basin, according to a March 2019 company press release. “Permian unconventional net oil-equivalent production is now expected to reach 600,000 barrels per day by the end of 2020 and 900,000 barrels per day by the end of 2023,” the release stated.

The company also recently entered into agreements to purchase renewable power in Texas for its Permian Basin operations. 

 

 

imarex Energy Co.

Cimarex Energy Co. is an independent oil and gas E&P company that invested $325 million in exploration and development during the second quarter, of which 83% was focused in the Permian Basin, according to the company’s second-quarter 2019 results report.

In the first half of the year, Cimarex brought 56 gross (37 net) wells on production in the Permian. Of those, 44 gross (32 net) wells were completed during the second quarter. As of June 30, there were 44 gross (20 net) wells waiting on completion and Cimarex was operating eight drilling rigs and two completion crews in the region, the report stated.

Production from the Permian averaged 188,703 boe/d in the second quarter, a 55% increase from the same quarter a year prior. Oil volumes averaged 70,669 bbl/d, a 45% increase from the second quarter in 2018 and up 9% sequentially, the report stated.

Cimarex added more Permian Basin assets through its acquisition of Resolute Energy Corp. in March in a deal valued at $1.6 billion, including debt.

In August 2018, Cimarex sold oil and gas properties principally located in Ward County, Texas, for $544.5 million to Callon Petroleum, according to a company press release. Production from these properties was reported at approximately 6,831 boe/d (73% oil) and was mostly from the Bone Spring Formation. The undeveloped acreage included 18,925 net Wolfcamp acres of which 11,500 net acres had rights to the base of the Wolfcamp, according to the release.

 

 

Concho Resources

In July 2018, Concho acquired RSP Permian Inc. in a $9.5 billion merger. “The transaction created the largest unconventional shale producer in the Permian Basin,” according to a company press release.

Concho’s second-quarter 2019 production was approximately 30 MMboe, or an average of 329,000 boe/d, according to the company’s second-quarter 2019 results report. Average oil production totaled 206,000 bbl/d, natural gas production totaled 737 MMcf/d and the company averaged 26 rigs during the second quarter. As of July 31, the company was running 18 rigs, including 11 rigs in the Delaware Basin and seven rigs in the Midland Basin, and utilizing seven completion crews.

In July Concho Resources Inc. and Solaris Water Midstream LLC formed a joint venture focused on “optimizing produced water logistics at scale in the Northern Delaware Basin,” a press release stated. “Under the terms of the agreement, Solaris Water will manage Concho’s produced water gathering, transportation, disposal and recycling for an area covering approximately 1.6 million acres located primarily in Eddy County, N.M. Concho will contribute 13 saltwater disposal wells and approximately 40 miles of large-diameter produced water gathering pipelines in exchange for cash and an equity ownership in Solaris Midstream Holdings LLC, the parent of Solaris Water.”

 

 

 

ConocoPhillips

ConocoPhillips holds about 800,000 net acres in the Permian Basin, which includes 87,000 net acres in the Delaware Basin and 58,000 unconventional net acres in the Midland Basin.

In 2018 ConocoPhillips reported average total net production of 38,000 boe/d, which included 21,000 bbl/d of crude oil, 5,000 bbl/d of NGL and 77 MMcf/d of natural gas, for its conventional Permian assets, according to a March 2019 company fact sheet. The company also reported 2018 average total daily net production of 28,000 boe/d, which included 14,000 bbl/d of crude oil, 6,000 bbl/d of NGL and 49 MMcf/d of natural gas, for its unconventional Permian assets. The company brought 36 operated wells online in 2018.

According to COO Matt Fox, the company’s Permian assets are considered early in their life cycle with significant growth ahead. He said it will be several years before the company reaches a plateau there but has a rigorous approach to development in the area.

“We will be, over time, increasing our activity in the Permian as we move from the mode we’re in just now, which is essentially making sure that we’re optimizing the well spacing and stacking and the order of which we tackle the various zones that exist within our Permian acreage. Once we’ve got that completed, then we’ll increase to more sustainable rig count there to build toward [the] plateau,” Fox said during the company’s second-quarter 2019 earnings call.

 

 

Devon Energy Corp.

Devon Energy’s operations in the Delaware Basin of West Texas and southeast New Mexico provide both oil and natural gas production from its core acreage position consisting of 280,000 net acres across multiple formations. The company’s current focus is in the oil-rich Wolfcamp, Bone Spring, Leonard and Delaware formations.

In 2018 the company reported net production of 75,000 boe/d (77% liquids) and 249 MMboe reserves in the Delaware Basin. Last year Devon sold 9,600 net acres of noncore Delaware Basin acreage in Ward and Reeves County to Carrizo Oil and Gas for $215 million, a press release stated.

According to the company’s first- and second-quarter 2019 results reports, Devon’s “strongest asset-level performance” for the quarters was achieved by its Delaware Basin operations in southeast New Mexico. In the second quarter, production from this play increased 58% year over year, driving volumes in the Delaware Basin to 120,000 boe/d. A key growth driver was 28 new wells brought online in the state-line area that averaged initial 30-day rates of approximately 2,100 boe/d per well, of which 70% was oil, according to the second-quarter report.

 

Diamondback Energy Inc.

Diamondback Energy is a pure-play Permian Basin operator with second-quarter 2019 production that averaged 280,400 boe/d (68% oil), up 149% year over year from 112,600 boe/d in the second quarter of 2018, according to the company’s second-quarter 2019 results report.

In the first half of the year, Diamondback drilled 172 gross horizontal wells and turned 151 operated horizontal wells to production.

In the second quarter, Diamondback drilled 89 gross horizontal wells and turned 69 operated horizontal wells to production, according to the report. Diamondback expects full-year 2019 guidance for average production to be between 277,000 boe/d to 284,000 boe/d, according to the report.

In November 2018, Diamondback acquired Energen Corp., which nearly doubled the company’s core acreage position, in an all-stock transaction valued at about $9.2 billion, company press releases stated.

Diamondback also acquired Ajax Resources last year in a transaction valued at about $1.25 billion. This deal also increased Diamondback’s Permian drilling inventory.

 

 

Encana Corp.

Encana’s second-quarter 2019 production in the Permian Basin averaged a record 104,000 boe/d (84% liquids).

“Encana continues to demonstrate efficiency gains with its four-rig program focused on cube development,” the company stated in its second-quarter 2019 results report. “A recent 14-well pad in Martin County, Texas, commenced production and is averaging 14,900 bbl/d after 90 days.”

This year the company plans to focus 75% of its activity in the Midland, Martin and Upton counties of the Permian Basin, according to the company’s corporate presentation released in August. Encana’s fiscal year 2019 plans in the Permian include having 105 to 120 net wells drilled and onstream.

In February Encana acquired Newfield Exploration Co. in an all-stock transaction valued at about $5.5 billion.

 

ndeavor Energy Resources LP

Endeavor Energy Resources LP is a private E&P company with more than 370,000 net acres in the Midland Basin. More than 95% of that total gross acreage is HBP. According to the company, it holds among the largest land positions in the Midland Basin.

The company reported record average net production of approximately 111,800 boe/d (73% oil) during the second quarter, a 60% increase from the average net production of approximately 69,800 boe/d (70% oil) for the same quarter the year prior, according to Endeavor’s second-quarter 2019 operating results report. Endeavor placed 38 gross operated horizontal wells on production during the second quarter, achieving an average 30-day IP rate of 1,141 boe/d (78% oil).

 

 

EOG Resources Inc.

EOG Resources reported a 7,050 boe/d gross 30-day average IP rate in the Delaware Basin in the second quarter of 2019. Crude oil and condensate totaled 1,950 bbl/d in the Wolfcamp, 1,300 bbl/d in the Bone Spring and 1,200 bbl/d in the Leonard Shale, according to the company’s second-quarter 2019 results report. NGL totaled 450 bbl/d in the Wolfcamp, 300 bbl/d in the Bone Spring and 600 bbl/d in the Leonard Shale in the second quarter. In addition, natural gas was reported at 2.9 MMcf/d in the Wolfcamp, 1.6 MMcf/d in the Bone Spring and 3.1 MMcf/d in Leonard.

EOG Resources brought online 63 gross (57 net) wells in the Wolfcamp, five gross (five net) wells in the Bone Spring and three gross (three net) wells in the Leonard Shale during the second quarter.

According to Hart Energy’s “Top 12 IP Wells in the Permian Basin” released in August, seven of EOG’s Wolfcamp wells made the list (data for the list were gathered from IHS).

 

Matador Resources Co.

Matador Resources’ operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in southeast New Mexico and West Texas.

During the second quarter of 2019, Matador focused on the exploration, delineation and development of its Delaware Basin acreage position in Loving County, Texas, and Lea and Eddy counties in New Mexico, according to the company’s second-quarter 2019 results report. Matador is operating six drilling rigs in the Delaware Basin. Delaware Basin average oil production increased 3% sequentially to 32,800 bbl/d, and Delaware Basin average natural gas production decreased 8% sequentially to 113.5 MMcf/d, each as compared to the first quarter of 2019, the report stated.

For the remainder of the year, Matador expects to continue operating only six drilling rigs in the Delaware Basin and has no plans to add a seventh rig to its 2019 drilling program.

 

 

Mewbourne Oil Co.

Headquartered in Tyler, Texas, Mewbourne Oil Co. develops oil and natural gas prospects, acquires leasehold interests and serves as the operator in the drilling, completion and production of oil and natural gas wells. Focusing on the Anadarko and Permian basins, the company operates more than 2,300 wells.

“Mewbourne has become the largest privately owned oil producer in America and the largest private producer in the Permian,” according to the company. In the second quarter of 2019, Mewbourne averaged approximately 80,000 bbl/d of oil and 300 MMcf/d in the Permian. The company has nine rigs running in southeast New Mexico.

 

Occidental

Occidental is the leading producer in the Permian Basin, following its acquisition of Anadarko in August. The company has operations focused on the Delaware and  Midland basins as well as the Central Basin Platform. Occidental manages operations in the Permian Basin through two complementary businesses: Permian Resources, which consists of growth-oriented unconventional opportunities, and Permian Enhanced Oil Recovery (EOR), which uses EOR techniques, such as CO₂ flooding and waterfloods.

Occidental is the largest injector of CO₂ for EOR in the Permian, a method that can increase oil recovery by 10% to 25%, according to the company. Occidental is advancing CO₂ EOR as a form of carbon capture, utilization and sequestration, a process that has the potential to reduce greenhouse-gas emissions. Occidental stores 18 MMtons of CO₂ per year in its operations.

Pre-acquisition, Permian Resources’ average production volumes exceeded guidance at 289,000 boe/d for the second quarter of 2019, an increase of 11% from the prior quarter due to improved well performance and development activity, according to Occidental’s second-quarter 2019 earnings release. The business delivered 26 of the top 100 wells while only drilling 7% of wells in the Delaware Basin, the report stated. Year-over-year Permian Resources’ production for the second quarter of 2019 increased by 44%.

On July 31, Occidental and Ecopetrol announced a joint venture to develop 97,000 net acres of Occidental’s Midland Basin properties, allowing Occidental to accelerate its development plans while maintaining operatorship, the report stated. The transaction is expected to close in the fourth quarter.

 

Parsley Energy Inc.

Parsley Energy Inc. is an independent oil and natural gas company focused on the acquisition, development, exploration and production of unconventional oil and natural gas properties in the Permian Basin.

Net oil production increased 10% from the first quarter to the second quarter of 2019 and increased 28% year over year to 86,600 bbl/d of oil, according to Parsley’s second-quarter 2019 results report. During the second quarter, total net production averaged 140,100 boe/d, and the company spudded 41 wells and placed 39 gross operated horizontal wells on production (33 in the Midland Basin and six in the Delaware Basin). “Parsley expects that development activity will remain weighted to the Midland Basin for the remainder of the year,” the report stated.

Looking ahead, Parsley plans to run a maximum of 11 development rigs and three to four frac spreads for the rest of the year. The company also increased its full-year 2019 net oil production guidance to between 85,000 bbl/d and 86,500 bbl/d of oil, the report stated.

 

 

Pioneer Natural Resources

Pioneer Natural Resources is a Permian pure-play company headquartered in Dallas, Texas.

Second-quarter 2019 Permian production averaged 330,000 boe/d and oil production averaged 206,000 bbl/d, according to the company’s second-quarter 2019 results report.

The company plans to operate an average of 21 to 23 horizontal rigs in the Permian Basin this year. This program is expected to place 265 to 290 wells on production. This activity level is projected to deliver 2019 Permian production of 320,000 to 335,000 boe/d and 203,000 to 213,000 bbl/d of oil, representing approximately 12% to 17% growth over 2018 production levels, the report stated.

 

Shell

Since Shell reentered the Permian Basin in 2012, it has high-graded its acreage, simplified the business, reduced costs and rapidly deployed technology to improve safety and increase production, according to the company. Shell operates in the Delaware Basin and is located in Loving, Ward, Winkler and Reeves counties. The company has interest in more than 500,000 acres (260,000 net acres) in the Delaware Basin with a focus on the Wolfcamp, Bone Springs and Avalon formations. Shell has more than 1,300 operated and nonoperated wells in the Permian, and production has increased to more than 120,000 boe/d in 2018 (operated and nonoperated).

 

 

 

WPX Energy Inc.

Independent energy producer WPX Energy has 130,000 net acres in the Permian’s Delaware Basin. The majority of this land is located in Loving County, Texas, and Eddy County, N.M. These assets have existing production from 10 benches in the Delaware play.

WPX’s Delaware production averaged 96,600 boe/d in the second quarter of 2019, which was 30% higher than 74,400 boe/d in the same period a year ago, according to the company’s second-quarter 2019 results report. Oil production of 46,400 bbl/d comprised 48% of second-quarter total Delaware production, and oil volumes were up 19% versus 39,100 bbl/d in the second quarter a year ago. WPX completed 16 Delaware wells during the second quarter, according to the report. 

The company had 5.6 rigs operating in the Delaware during the first half of the year and plans to have five rigs operating in the second half of the year.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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New Technology Primed And Prepped For Permian Challenge

Better wells, higher efficiencies and improved logistics are becoming the norm as contractors and operators alike ramp up the development of solutions.

 

 

Players entrenched in the booming Permian Basin oil play of West Texas and southern New Mexico are working their way through the region’s growing pains—low takeaway capacity, limited workforce and logistics challenges—with aims to emerge with both success and profit from what pundits are calling one of the world’s most important oil provinces. Technological advances used to unlock the full potential of the reserves in the region’s Delaware and Midland basins are still being matured, and production is set to increase by as much as 4 MMbbl by the end of 2022, thanks in large part to new pipeline projects being brought online. The bigger picture for future activity in the area is a bit of a mixed bag.

Operators in the Permian have cut spending plans for the balance of the year, and the rig count has been on the decline over the past several months. According to Enverus Drillinginfo, the Permian rig count has dipped by nine units from mid-July to mid-August and by more than 40 over the past 12 months. The lower activity can be attributed to the large number of drilled but uncompleted (DUC) wells in the area. Almost half of the nation’s 8,100 DUC wells are located in the Permian, according to the U.S. Energy Information Administration. The backlog has led some contractors to scale back plans to introduce new equipment to the market. Liberty Oilfield Services’ CEO Chris Wright told attendees at an August energy conference in Denver that the company would wait to deploy its newest hydraulic fracturing fleet until market conditions improve. 

Permian operator Devon Energy told investors in August that it has transitioned to full-field development across a significant portion of its core acreage in the Delaware Basin. The area’s Wolfcamp Formation will account for as much as 65% of the company’s development program in the coming years. The company has touted average 30-day production rates of about 2,500 boe/d from more than 50 wells across the Leonard, Bone Spring and Wolfcamp formations in the first half of 2019.

“Our outstanding results year to date are benefiting from the learning attained from our appraisal work performed in prior years,” said Devon COO Tony Vaughn. “During this appraisal activity, and our work in other plays across the company, we have a strong understanding of the subsurface that allows us to identify the best landing zones, understand parent/child dynamics, along with the appropriate well density per section and deploy optimized completion designs to capitalize on that knowledge.”

While the riddles of the Permian plays are being unraveled, challenges for the industry in the region remain ever-present. Beyond export logistics, operators are still combating steep decline curves and initial flow issues related to well proximity as well as larger, looming factors like commodity price uncertainty. With many operators deferring additional spending, the Permian will likely suffer a dip in drilling activity during the second half of the year, and perhaps into 2020. Production, however, remains forecast to increase as more routes for oil and gas out of the area open up and operators tend to some of the overhang in the region’s drilled, undeveloped well backlog.

Tools of the trade
Service giant Halliburton has worked diligently both within its walls and with clients in the field over the past few years to bring a new rotary steerable system (RSS) to market that has the ability to tackle some of the Permian’s toughest challenges. The result was the iCruise intelligent RSS that combines smart technology—advanced electronics, sophisticated algorithms, multiple sensors and survey packages, and high-speed processors—with some of the highest mechanical specifications on the market. The goal was to integrate the latest technology and provide an intelligent system to provide higher ROP, improve steering and use the latest maintenance techniques to drive higher reliability.

 

 

“Our clients using the iCruise RSS today number in the double digits,” said Faraaz Adil, Halliburton business development manager, technical, Permian Basin. “If I look at the total number of rigs that we have in the Permian, I think roughly 20% to 25% are using rotary steerable systems. We are confident that the iCruise RSS is going to gain Halliburton market share very quickly based on the performance we’ve seen and the successes we have had across the Delaware and the Midland basins.”

The iCruise RSS is designed for very precise steering. The bottomhole assembly (BHA) is modular and can be set up for drilling curves with doglegs up to 18 degrees per 100 ft. It also can be set up to drill faster laterals. The steering precision is driven by three distinct dual-phase measurements feeding into advanced control systems. The measurements are being made at 1,000 Hz allowing for very precise control of direction.

“Several of the launch models used when we were designing the iCruise system have been employed as a building block for other automation systems in the bigger picture,” Adil said. “The idea behind the whole thing was to be far more predictable and repeatable in drilling complete wells than where the industry is today. Our automation system, in general, is very different in each phase of drilling. When drilling a vertical section or laterals, the tool will actually control itself, lining up on the target and drilling with very little variation in inclination or azimuth.”

The iCruise RSS uses a new automation service called LOGIX automated drilling director, a Halliburton Sperry Drilling technology that was created around a complex digital model of the BHA and a digital twin of the wellbore. LOGIX software is installed in surface systems and supplies the commands to the downhole tool to precisely steer the wellbore through the reservoir matching the directional plan. It creates model-based optimization to drill to a plan or target on an optimized trajectory while improving drilling efficiency. It uses machine learning to continually compute the optimal course and provide steering commands to the iCruise RSS.

Halliburton continues to expand its intelligent systems initiative throughout the oilfield life cycle—from drilling to completion. On the completions side, there is the Prodigi intelligent fracturing service. Designs in unconventional fracturing require many parameters to achieve optimized stimulation treatment outcomes. The Prodigi service can automatically adjust pump rates during the breakdown process, driving consistent stage-to-stage performance, by utilizing real-time measurements and proprietary rate control algorithms. Adaptive rate control also can support a more efficient breakdown at the perforation clusters, improving the connectivity of fractures.

“The impact of execution on the success of a stimulation treatment is often underestimated,” Adil said. “People believe that if you pump a certain amount of fluid and proppant into a formation that should give you a result. That is not always the case. It is very necessary and important to understand how you pump that fluid and proppant into the formation. One of the aspects of that is how you go in and break down the formation before you actually pump fluid and proppant into it. So that breakdown process can greatly impact the final results from a production perspective as well. The Prodigi intelligent fracturing service utilizes an automated control mechanism to optimize this process and allows for the most efficient breakdown that we can achieve.”

While the tool is working, it is constantly looking at responses and taking measurements and reacting to what it detects. The major benefit is real-time optimization, matching the required rate and pressure needed. The operator isn’t exactly depending on the human sitting with the pump and adjusting the rates. The software takes control of all of that. It does not matter what time of day it is or who is there with it; it is going to perform the same way stage after stage.

“Prodigi service is constantly looking at the pressure responses when you are conducting a frac job,” Adil said. “It is picking up real-time wellbore pressure information and feeding that into the internal algorithm that allows the service to come to a decision effectively faster than a human would be able to make the same call. We try to keep the amount of information fed into the system at a minimum. The way the product is designed is that it is not dependent on a lot of information that could be variable from different sources. It is picking up the real-time pressure inputs and making decisions based on that.”

Since Halliburton rolled out the Prodigi service as a commercial tool for many of its clients across the Permian, the tool has proven its ability in both the Delaware and Midland basins.

No more cement plugs
For decades, Weatherford’s customers’ only options for openhole sidetracks were openhole cement plugs or deployment of a two-trip sidetracking whipstock system. Both of these options are costly or full of risk. Weatherford developed AlphaST, the world’s only single-trip openhole cementing and sidetrack system that enables the cement and sidetrack in a single trip for the first time ever.

 

 

 

“In the Permian, depending on the application and/or the client, about 10% of the wells drilled get sidetracked—planned or unplanned,” said Tom Emelander, U.S. GeoZone operations manager for casing exits, openhole whipstocks and multilaterals, at Weatherford. “The vast majority of these sidetracks are done off cement plugs. Everyone does a handful of these cased-hole and openhole systems. We do as well. But the vast majority of these openhole sidetracks are done off cement. The success rate of plugs depending on application and area—the feedback we get from our drilling services guys and from the operators themselves—is anywhere from 50% to 75%, depending on depth, hole size and formation. The typical time savings we see with the AlphaST versus a successful plug is in the neighborhood of two to three days. That is significant. That is a step change versus the best-case scenario that isn’t happening consistently. There is substantial value to the client in the form of time savings, such as fewer trips, eliminated cement curing time and eliminated failed sidetracks, which result in earlier well completion and production for each one of these wells.”

Those savings are realized when compared to cement plug or two-trip sidetrack systems. As much as half of the time, an operator is not successful on the first cement plug, meaning they will have to go and set another plug. With the second plug, the success rate could be lower because the hole already has been left exposed for, in some cases, several days. One way to counter that might be to change the operation from the first plug to the second, but that usually comes at the expense of the cement or more often in the time spent letting that cement cure, resulting in customers giving up more time or spending more money each time a plug is unsuccessful.

“As an example, looking at the average spread rate, cost of cement [and] cost of the AlphaST versus a two-plug attempt, we’re saving approximately $350,000 and a week to production time,” Emelander said. “That itself is pretty eye-opening, but when you look at it in terms of large-scale drilling—operators with 30 to 40 rigs—if they are sidetracking at that average pace across a 100-well program, you could be saving $2.2 million and 50 days to production quicker. That’s massive. That’s all money that you can put back into the budget. To get those values, we’re assuming most of the cement plugs are successful. But a couple of them are likely going to take more than one attempt. That is where you really start adding cost and days to the operation. If it is unplanned, you are going to exceed AFE [authorization for expenditure] pretty quickly.”

In developing AlphaST, Weatherford was determined to eliminate a trip compared to existing whipstock systems and eliminate the need for cement plug sidetracks. The crucial innovation was to actually save a trip out of the wellbore to pick up a dedicated drill off BHA and drill off the whipstock. Weatherford then used its proven, reliable conventional system, which facilitates setting the anchor, and engineered a new mill that attaches to the current whipstock. Customers can now drill off with attached mills without the need to come out of the hole after cementing to pick up another BHA.

“AlphaST reduces cost and risk,” Emelander said. “All the same reliable processes are utilized. We added an extra two mills, the first being a proprietary design. It is generating tremendous customer excitement.”

Shape of water
Water logistics in the Permian Basin continue to evolve as a leading challenge for producers in the region from both a supply and disposal perspective. Although water infrastructure and related logistics have improved over time, operators are still pushing to reduce completion costs and long-term operating costs for handling produced water. As completions continue to grow, operators are increasingly reaching out to third parties for cost-effective disposal and reuse options and for help in handling the growing volumes of produced water and source water needed for fracturing. On average in the Permian, the water-oil ratio is estimated at 3 bbl to 4 bbl of produced water for every barrel of oil produced. As a consequence of growth, large-scale gathering infrastructure consisting of networks of pipelines, disposal wells and recycling facilities are being permitted, constructed and operated, diminishing the need to truck water. Additional benefits include the aggregation of large volumes of produced water to support recycling and a substantial reduction in the use of freshwater resulting from changes in hydraulic fracturing fluid chemistries, which have relaxed requirements for the treatment of produced water for fracturing.

Solaris Water Midstream has been expanding its infrastructure footprint in the Permian for the past several years. With assets in the Midland and Delaware basins, the company has been recycling in the Midland Basin for more than two years and started water recycling at its Lobo Ranch facility in Eddy County in July. In its first few months of operation, Lobo Ranch recycled up to 80,000 bbl/d of produced water. In New Mexico’s Lea County, Solaris Water is mobilizing the Bronco Produced Water Recycling and Blending Center and expects to begin delivering treated water to operators from that facility in late September. The Bronco facility also will have the capacity to treat in excess of 80,000 bbl/d. Solaris Water has plans to construct additional large-scale recycling and blending facilities in Eddy and Lea counties over the next few years.

 

“Solaris Water’s growing integrated pipeline network in the Delaware Basin runs approximately 350 miles across Eddy and Lea counties in New Mexico serving numerous major customers and further extends into Culberson and Loving counties in Texas,” explained Solaris Water’s CEO Bill Zartler. “This system consists of interconnected, large-diameter trunk lines that support the bi-directional flow of water and related gathering systems and saltwater disposal [SWD] wells. Today the system extends 40 miles north into New Mexico from the Texas state line with permitted rights of way to extend the network even farther to the north.”

To provide perspective, most water trucks carry about 130 bbl. Solaris Water is currently moving 500,000 bbl/d in the Delaware and Midland basins—or the equivalent of over 3,800 trucks. While emerging technologies continue to play a role in the water treatment end of the business, the current focus for many in the industry is ramping up operations to meet producers’ current and future needs.

“I think what’s different now is the scale of water systems, the volumes being moved, working with multiple operators at the same time and aggregating their produced water before treatment and recycling,” Zartler said. “The water quality specs for fracking have also changed. While operators have a standard spec, today the level of treatment required to meet this spec has been reduced. Today, the industry is more focused on reducing total suspended solids, iron, H₂S and bacteria and is not as concerned with dissolved solids. We are no longer looking to clean produced water to almost potable levels. With slickwater fracs and more effective chemistries and friction reducers, operators can effectively use saltier water for fracking, which has dramatically reduced the need for treatment and related costs.”

 

 

"With slickwater fracs and more effective chemistries and friction reducers, operators can effectively use saltier water for fracking, which has dramatically reduced the need for treatment and related costs.”—Bill Zartler, Solaris Water Midstream

He continued, “The water business is also a business in transition, from small outfits with a handful of trucks and a couple of disposal wells to a full-fledged midstream service entity. As it evolves, what we see today is either upgrading or consolidation of saltwater disposal companies into companies with large pipeline networks and a focus on gathering systems and multiple SWDs, which requires a larger amount of capital. We’re also seeing producers continue to focus on capital efficiency. Producers made the evolution 25 years ago to divesting their natural gas and crude gathering systems. Water midstream is evolving in the same way. Given the intense focus on not spending cash and the ability for the upstream industry to raise money, certainly in the public markets, producers are doing what they can to eliminate capital expenditures for services a third party can provide at a fair price. We think we will continue to see producers evaluating the sale of their midstream water assets to raise capital and outsourcing their water needs to proven midstream players that have large integrated water systems in place—systems they continue to expand.”

Water management
The Permian’s shift to a more sustainable water model is not lost on the management of XRI. The company purchased the water treatment and recycling division of Fountain Quail Energy Services in April and recently completed its Northern Delaware Basin Supersystem with water pipeline infrastructure spanning more than 125 miles throughout the core areas of development activity in New Mexico’s Eddy and Lea counties. The cost of water treatment and recycling technology is now attractive versus the all-in cost of water disposal.

“The economics of treatment and recycling on a full-cycle basis are superior to saltwater disposal of produced water for our customers,” XRI CEO Matthew Gabriel said. “When paired with the nonpotable water sourced on our owned water midstream systems in the Delaware and Midland basins, and broad water distribution networks of approximately 300 miles, it is now possible for our customers to reuse, blend or swap 100% of their produced water to obtain recycled water of virtually any specification.

“XRI is focused on the continued development of our midstream asset base, providing long-term takeaway of produced water from our customers and subsequently treating that water to meet the water quality specifications for a multitude of other users on the network. Providing large-scale treatment and connected infrastructure utilizing automation and advanced water data systems is the optimum way to ensure that XRI is providing the most cost-effective and long-term water management solutions to serve the evolving needs of the Permian Basin’s most prolific oil and gas producers.”

 

 

A pair of new laws, New Mexico House Bill 546 and Texas House Bill 3246, also have gone a long way to clearing up any murkiness surrounding produced water ownership. Both determined that oil and gas operators control the produced water and they could then use, dispose of, transfer or convey to recycling companies, which then take over legal responsibility. The New Mexico law went into effect in July, followed by the Texas law in early September. With that question answered, longer-term players and private-equity groups have a clearer path to returns when deciding to invest in the sector. Many believe that the growth potential if properly funded, could yield a new, robust service industry, not unlike the conventional midstream services model.

 

“As E&P companies continue prolific development of the Permian Basin, responsible and effective water management is integral to the success of the industry.”—John Durand, XRI

“As E&P companies continue prolific development of the Permian Basin, responsible and effective water management is integral to the success of the industry,” said John Durand, XRI president. “The evolution of water midstream will likely mimic the conventional midstream natural gas sector, where a few large entities that, through consolidation, form large interconnected combinations of assets and systems. Like the midstream natural gas pipeline networks of today, it is not difficult to envision a scenario where large water ‘super networks’ will exist to maximize efficiencies and ensure that companies such as XRI continue to provide large-scale, full-cycle water management solutions that focus on the principles of resource preservation and social responsibility in order to maintain viability and sustainability for the industry.”

Blinded by the light
The pursuit for oil in the desert of West Texas has been a draw for oil and gas operators for almost 100 years. From the earliest days of the Westbrook Field discovery and the Santa Rita No. 1 to today, the Permian Basin reinforces the old wildcatter’s adage—the best place to find oil is in an oil field. There are times, however, where oil and gas exploration has unintended consequences, and everyday technology—something as simple as a light bulb—becomes a source of contention.

When operator Apache started looking at a new trend in the west end of Reeves County, Texas, back in 2015, there wasn’t much buzz about the area. It was gas prone. The geology was complex. It was off the radar of most industry players. By the time Apache announced its findings for the area it had dubbed Alpine High, it had established a vertically stacked resource with estimated reserves of 75 Tcf of rich gas and 3 Bbbl of oil in place. And it has only gotten bigger. The discovery and subsequent expansion did not go unnoticed by a curious neighbor to the south. Roughly 20 miles from the Reeves County border situated in the Davis Mountains of Jeff Davis County, the McDonald Observatory, part of the University of Texas, was established in 1932 to study the cosmos in one of the darkest places on the planet. The observatory, home to the world’s third largest telescope, had concerns about encroaching light from oil and gas development that has crept nearer to its Mt. Locke location. But something that could have become adversarial instead became a welcomed collaboration.

Apache and the observatory joined forces with dark skies initiative coordinator Bill Wren and the McDonald Observatory to implement best lighting practices to protect the dark skies of West Texas. The operator conducts weekly audits of about 1,600 lights across Alpine High to ensure compliance.

“You want to mount high and aim low,” said Wren in an August interview with Marfa Public Radio. “Keep your light on your site. Another thing that is in the recommended lighting practices is to go with a low-temperature light.”

Other companies are also looking to reduce their light “sky print” and adhering to the observatory’s published “Recommended Lighting Practices” guide that is endorsed by the Permian Basin Petroleum Association, Texas Oil & Gas Association, American Petroleum Institute, University Lands and the Texas Independent Producers and Royalty Owners Association. Elements being used by the industry to cut down on light pollution include proper shielding and aiming of existing fixtures, which improve visibility and reduce wasted up-light. There also has been the deployment of new lighting systems that take advantage of light-emitting-diode technology and promise better directionality and reduced fuel consumption. 

“As we work to keep the skies dark in West Texas, our emphasis is light positioning and light fixture shielding,” explained Apache spokesman Phil West. “With these two techniques, which control the light direction, the majority of the light impact is mitigated. Light sources that are properly aimed and shielded are more efficient, and that generally requires fewer lights throughout our operations.”

In July Apache donated $257,000 to McDonald Observatory that will be used to fund the observatory’s ongoing efforts to preserve the dark West Texas skies that make research possible and provide unsurpassed views of the universe to visitors.

 

 

 

 

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In April the Permian became the highest producing field in the world—pumping about 4.2 MMbbl/d. To study the impact of the Permian’s continued production growth, Hastings Equity Partners commissioned a whitepaper in partnership with the University of Houston Energy Research titled “Opportunities and Challenges in the Permian.”

“We wanted to understand the takeaway capacity of the Permian and where the incremental oil will end up,” said Ted Patton, founder and managing partner of Hastings Equity Partners.

According to the study, advanced technologies such as enhanced seismic data gathering capabilities, horizontal drilling, hydraulic fracturing and multipad development techniques have allowed operators to realize cost savings of nearly 40% to drill and complete a well.

“Clearly, the Permian Basin has defined our students’ careers in the industry. So the research was largely driven by the motivation to create awareness among faculty on educating the students on the Permian,” said Dr. Ramanan Krishnamoorti, chief energy officer at the University of Houston and co-author of the research.

The report disclosed a few unanticipated findings, including the industry consolidation in the Permian Basin and the transportation challenges.

Industry consolidation
Major industry operators are estimated to produce more than half of the oil in the Permian over the next four years representing “a historic shift in economic power,” according to the study. As Patton pointed out, oil majors such as Exxon Mobil and Chevron have designed aggressive strategies to consolidate production, resources and supply chains that will meet the majority of the domestic needs.

Consolidation by majors and increased pressure on the independents will lead to the gradual erosion and ultimate destruction of enterprise value among many oilfield service companies due to the lack of pricing power, Krishnamoorti said.

If major operators continue acquiring acreage in the Permian as well as ownership stakes in the pipelines, downstream refineries and petrochemical facilities, then independent producers that traditionally sell to the majors will need to market internationally and export overseas, according to the findings of the study.

“The Permian Basin used to be a place where wildcatters reigned, and now with technology, the economy is being driven by manufacturing,” Patton said. He added that independents are facing new limitations from the investment community to limit production volume to what can be achieved with cash on hand. At the same time, both Exxon Mobil and Chevron have each announced plans to produce 1 MMbbl/d. The inevitable result will be mergers by independents in an effort to survive, he said.

Bottlenecks
Pipeline capacity for the crude produced in the Permian has been a major bottleneck, but it will move back into balance with demand by the middle of 2020, if not before, according to Krishnamoorti. He added that the shortage of pipeline capacity and the resulting inability for producers to transport oil from the region has caused a significant discounting of the produced crude oil in the Permian and also has resulted in increasing the inventory of drilled but uncompleted wells.

The study also revealed that although more than $90 billion is currently invested in construction projects for terminals, LNG, refining and petrochemical facilities along the Texas and Louisiana Coast, with another $200 billion planned for the next decade, construction can’t keep pace with the supply of oil coming out of the Permian. “The majority of the recent incremental capacity is and will continue to be directed at the Port of Corpus Christi,” Krishnamoorti said.

Large volumes of U.S. crude are exported worldwide via marine routes. According to the findings of the study, another bottleneck facing the Permian over the coming years is the inability of ports to refill very large crude carriers (VLCCs), which are designed to carry 2 MMbbl of crude and are the largest and most economical vessels used for crude oil export.

Waterways along the Gulf Coast don’t provide 75 ft of depth, which is needed to accommodate fully loaded carriers and as a result require lightering. The partial loading of VLCCs is a cost center for crude transport. Using several smaller ships for lightering adds to these costs. While the costs are relatively negligible for short distances, they compound to significantly higher expenses over longer distances such as for crude transport to Asia.

The Louisiana Offshore Oil Port is the only U.S. facility that can harbor fully loaded VLCCs. The Louisiana Offshore Oil Port was previously used exclusively for imports and was recently modified to accommodate exports. The demand for U.S. crude has highlighted the need for deepwater terminals off the coast of Louisiana and Texas. Projects have been proposed, but permitting and execution permissions will delay progress, thereby creating additional bottlenecks, according to the study.

Environmental concerns
The research also recognized the need to address sustainability issues including natural gas flaring and water management. The associated gas cannot be appropriately valorized because of the absence of gathering and transportation pipelines and the reluctance of operators to invest significantly in gas infrastructure. In addition, technology to reinject the gas into the formation has not been fully developed to make it a viable option to handle the associated gas.

The pipeline infrastructure to evacuate the oil out of the Permian will be built out on schedule with increased Permian production. However,  environmental concerns have recently caused some doubts on the actual development and deployment of these pipelines, the study reported.

For instance, deployment of pipelines across the Texas Hill Country faced stiff challenges from the local community. Moreover, the development of processing and storage units near Corpus Christi also encountered similar opposition from the community.

The flaring and direct release of natural gas have resulted in a negative reaction toward the growth of Permian production. Also, the report suggests that the issues of water usage for hydraulic fracturing and management of produced water continue to grow and the lack of solutions are causing considerable dismay among local communities in these areas.

Conclusion
The study forecasts a bright future for the continued growth of production from the Permian Basin. “[That] won’t happen without continued planning, infrastructure growth and adjustments to market condition,” Krishnamoorti said.

He added that all the operators, especially independent producers, “must adapt to market realities and become adept at maneuvering through the export process. Gulf Coast ports and the ancillary infrastructure will have to learn to manage the additional congestion and technical obstacles posed by increased crude oil and LNG exports.”

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Super Lateral Integrates Services To Increase ROI

A Delaware Basin program combined a high-performance drilling fluid system, RSS and drillbits to drill a 3.14-mile lateral.

 

 

Extremely long laterals in the Delaware Basin are key to a development strategy aimed at improving return on investment (ROI) through greater reservoir exposure at a lower cost. Recent drilling of a 3.14-mile super lateral with a Permian Basin record measured depth (MD) of 26,745 ft was achieved with greater efficiency and less risk while overcoming multiple challenges in the Wolfcamp reservoir interval. The operator estimates the well will significantly improve recovery with only a minimal increase in cost compared to shorter laterals.

For on-target drilling of the 16,574-ft lateral, an integrated approach using Halliburton drilling fluids, a rotary steerable system (RSS) and bits was used. The combination satisfied many drilling requirements including low equivalent circulating density (ECD), high fluid stability, minimal torque and drag, a high penetration rate and ultimately a high-quality, on-target wellbore.

Halliburton’s approach integrated a BaraXcel high-performance nonaqueous fluid (NAF) system, the iCruise intelligent RSS, a NitroForce high-flow, high-torque motor and a GeoTech GTi PDC bit.

The well in Eddy County, N.M., is part of a larger drilling program based on very long laterals. The pad included four wells, including this well, with 3-plus-mile laterals. All four wellbores were successfully drilled using Halliburton’s integrated approach.

The extreme lateral lengths in these designs contribute to a variety of challenges. It is important to maintain low torque and drag and provide efficient hole cleaning in the long holes. Water influx, weak zones and barite sag during long trips must be addressed. The conditions require a highly stable fluid system and tight control of ECD. Steering accuracy and hole quality are very important to delivering an effective, on-target wellbore, and efficiency requires the wellbore be drilled at optimum penetration rate and footage. Development and execution of the best solution depended on close coordination between the multidiscipline service provider team.

 

 

 

Fluid system
The high-performance drilling fluid system BaraXcel has an extensive track record in the area due primarily to its stability, hole cleaning capacity, and torque and drag reduction. Its custom design is based on extensive laboratory testing and field monitoring. Area variations by well typically include adjustments for formation water salinity in the fluid or to mitigate increased water ratios.

For this operator, prior experience with the fluid system included 13 super laterals with measured depths in excess of 21,000 ft. Nine of them were drilled to 24,000 ft MD or longer.

Additional fluid design iterations were developed to drill the wells because the operator uses several different base oils. The system was modified and tested for stability and compatibility, and treatment guidelines were established to ensure maintenance of the desired properties.

One of the key challenges is water influx from nearby completions. While the situation is typically detrimental to an oil mud, the system has a greater water tolerance than traditional NAF systems, allowing properties to be closely maintained.

The fluid system’s lower ECD has helped drilling stay within a narrow pressure window determined by a weak zone higher in the hole. The fragile gel structure of BaraXcel averted barite sag during long static periods and helped avoid pressure surges when breaking circulation.

Baroid technical and field teams closely monitored fluid properties while drilling and close collaboration helped ensure optimal RSS and motor selection and settings based on the fluid system properties. 

The engineered fluid system delivered excellent hole cleaning and ECD control throughout the lateral section. No lost circulation incidents occurred while drilling the lateral, and torque and drag remained within acceptable ranges.

RSS and motor
The iCruise intelligent RSS drilled the lateral with minimal deviation from the centerline. The wellbore reached total depth accurately and on target with minimal tortuosity.

In addition to collaboration on fluids, the team collaborated to optimize the bit for the formation and the RSS. Because it is a hydraulically controlled tool, it is important to understand fluid system characteristics, including mud weight, components and base fluid (oil or water), and their effects on the RSS. For example, fluid characteristics can change flow to the RSS pads and steering.

Fluid properties also figure in mud pulse telemetry, which can affect data transfer. In the subject well, a potential issue due to water influx was resolved by BaraXcel fluid’s higher water tolerance. This characteristic also helped manage torque that would have risen with the addition of water to a conventional oil-based system. 

Directional accuracy that was critical in the long hole was aided by the ability to make adjustments to RSS steering sensors while drilling. Adjusting the sensors, which take directional readings at more than 1,000 times per second, avoided the need to mitigate vibrations that typically complicate conventional directional readings.

Autonomous drilling made a significant contribution to improving accuracy and minimizing tortuosity. Making small directional adjustments downhole versus the surface resulted in a faster response time for delivery of a smoother, on-target wellbore.

A NitroForce high-flow, high-torque motor was selected to complement the RSS and bit. It was configured for a 0.23-revolutions-per-gallon motor running at about 600 gpm. The slower motor speed was selected to help extend bit life and achieve as long a run as possible. Lack of wear on the GeoTech GTi bit after drilling the long interval suggests it may be possible to increase motor speed to improve ROP further.

Drillbit
A GeoTech GTI 8½-in. PDC matrix body bit used in the lateral achieved the model’s longest run for the operator. The bit drilled a total 8,162 ft in shale, sandstone and limestone, and it completed the run in 140.8 drilling hours for an average ROP of 58 ft/hr—a rate in line with shorter offset runs. The bit finished the run with a very good dull condition.

The six-blade bit with 16-mm cutters was designed using the Design at Customer Interface approach to focus on the application and operator objectives. Input from deployed technology, field operations and business development groups provided the basis for fast customization for the application. The GeoTech GTi bit model is designed for use with the iCruise RSS to enhance steerability and cutting efficiency. It features PDC cutters for higher average ROP and footage. The Stega efficient cutter layout technology also was used to optimize backup cutter placement for increased durability, and the Cerebro electronic data capture system collected performance-enhancing data that will be beneficial for future runs.

Highly abrasion-resistant PDC cutters were important to drilling the very long lateral. The cutters were specified to increase the amount of rock removed with less wear to achieve a high average ROP and up to four times the footage of earlier technology.

Increasingly longer laterals are being drilled to improve reservoir exposure at a lower cost. Efficient, trouble-free operations benefit from the integration of fluid, RSS and bit services to help the operator maximize asset value and minimize risk.

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Permian Poised To Deliver Strong Oil And Gas Production Growth

 

This article focuses on the outlook for the Permian Basin, which will continue to grow beyond 2029 driven by its large aerial extent of economic drilling at oil prices of less than $50 WTI. Rig count trends, top operators, midstream buildout, merger and acquisition (M&A) activity and a topical discussion on well spacing are presented.

After supporting Permian operators to spend vast sums of money during 2016 and 2017 to buy land inventory, Wall Street shifted its scorecard on the industry from one of a discounted cash flow or net present value (NPV) approach to one predicated on demonstrating sustainable free cash flow to return to shareholders. This paradigm shift from Wall Street has been abrupt, and public E&P executives hear the message and are pivoting business strategies. Given the nature of the industry, the pivot will take some time but is well underway. This will impact the rate of growth in the Permian as less capital is put into the ground. But the basin supply dynamics remain strong. The Wall Street sentiment to E&P companies is currently negative, but industry innovation continues strong and more efficiencies are on the way. Enverus Drillinginfo is confident Permian Basin economics are strong enough to both grow production and return cash to shareholders. At some point, Wall Street sentiment is expected to shift back and support the great advances many companies are making.

Production forecast
Enverus Drillinginfo forecasts U.S. oil production to grow by 1.5 MMbbl/d in 2019 to an average of 12.3 MMbbl/d, an increase of 13% over 2018. This is moderated from the 2018 record growth of 17%, or 1.6 MMbbl/d. From 2020 to 2023, production growth will continue to moderate and increase by another 3.2 MMbbl/d (or an average 6%) to reach 15.5 MMbbl/d in 2023 (Figure 1).

 

 

The Permian Basin leads U.S. oil growth and accounted for 1 MMbbl/d, or 62%, of the record 2018 growth. The Permian will continue to lead and is forecast to grow by another 0.8 MMbbl/d in 2019 to an average 4.3 MMbbl/d. By 2023, Permian production is forecast to average 5.7 MMbbl/d.

In 10 years U.S. production is expected to reach about 17.3 MMbbl/d, at which time the Permian will account for 40% (or 6.8 MMbbl/d) of U.S. production—up from its 35% share this year. Longer term, the Permian will continue to grow beyond 2029, which is forecast to underpin a flattening U.S. oil production profile.

For U.S. gas, growth also continues. Although, like oil, it is at a slower pace from recent history. From 2015 to 2019, gas production grew by 14.8 Bcf/d to reach a forecast average of 88.8 Bcf/d in 2019. Growth will slow by nearly 60% to add another 6.4 Bcf/d by 2024. The Permian and the Northeast will contribute equally to the growth at 2.2 Bcf/d during the next five years (Figure 2).

 

 

 

 

Well-level economics driving growth
This growth in U.S. oil production is driven by substantial swaths of land that are currently de-risked and economic at prices of $55 WTI or less. While the Permian accounts for much of this profitable drilling inventory, portions of virtually all other major resource plays contribute to this growth, including the Bakken and Eagle Ford.

Based on a bottoms-up methodology, Enverus Drillinginfo maintains well economics on more than 200 distinct groupings of areas predicated on well history and current cost economics. Shown in Figure 3 are breakeven economics for oil. There is a substantial inventory that is profitable based on half-cycle (driven by drill and complete costs) economics at oil prices less than $50 with a minimum return threshold of 12.5% (Figure 3). The second key takeaway from the breakeven analysis is the continuum of plays that become economic as oil prices rise. The “Plays on the Margin” noted in Figure 3 become economic at a WTI price of between $50 and $65.

 

 

 

In aerial extent, the Permian’s Wolfcamp, Spraberry and Bone Spring formations lead the inventory counts of drillable economic locations. Within the Permian, the top tiers of these formations lie in the Delaware Basin with breakeven economics of less than $33/bbl. Average Delaware Basin breakevens are $39/bbl, while in the Midland Basin the northern section rivals the Delaware while the southern section remains challenged at $50 WTI (Figure 4). 

Other leading areas outside of the Permian include the top areas in the Eagle Ford such as DeWitt County, Texas, and the Sugarkane area of Karnes County, Texas. The Antelope area of the Williston Basin also is leader in the race for breakeven economics. 

 

 

 

Permian top operators
With its transformational $57 billion buy of Anadarko Petroleum, which closed Aug. 8, Occidental Petroleum extended its lead as the top Permian oil producer, currently accounting for more than 10% of the basin’s gross operated production and more than 50% ahead of the second largest producer, Concho Resources. 

Figure 5 shows the top 15 producers in the Permian that collectively operate 57% of the oil production. Enverus Drillinginfo notes a long tail of smaller operators. Currently, there are more than 300 companies operating in the Permian that produce 100 bbl/d or more.

Noteworthy is that the share of the top 15 has remained consistent since 2017 at 57%. The collective growth rate for this group dropped from 38% in March 2017-2018 to 27% in March 2018-2019. Perhaps more striking is that over this two-year period, the top 15 grew production by a striking 76%.

Certainly, as companies get larger, they have performed admirably with growing production. Growing from a large base of production presents a complex set of business and operational issues. As time marches on, these large operators continue to find business process improvements that positively affect cost structure and consistency.

 

 

 

 

It is in this time frame that the Permian rebirth started in earnest, driven in large part by the opening of the Delaware Basin. From that trough in April 2016, the Permian rig count consistently rose by nearly 400% over 2.5 years to reach a recent peak of 505 on Nov. 16, 2018, at which time its share of the U.S. rig count rose to 42%. It is this trough to peak rig activity that spurred the record Permian production growth in 2018, which is continuing into 2019.

Recently since its peak of 505 in November 2018, Permian rig counts have declined by about 15%, which is setting up for a slower production growth rate in 2019 and beyond. The correlation between rig counts and production, while largely directionally consistent, are not directly correlated as operators are continuously innovating and moving toward drilling longer laterals and improving drill times. Regarding drill times, thus far in 2019, average spud to release is 19 days, an improvement from an average 21 days in 2014.

Permian oil takeaway forecast
As Permian oil production was rapidly ramping, midstream operators moved in quickly to begin building additional long-haul capacity directed to the Texas Gulf Coast export markets (Figure 7).

 

 

 

 

 

Capacity out of the Permian is expected to increase by 2.1 MMbbl/d this year. Plains All American’s Cactus II pipeline, originating in Wink, Texas, and terminating in Corpus Christi, Texas, with a 650,000-bbl/d design capacity, is complete and has begun commercial operations, with full service to Corpus Christi expected by the end of the first quarter of 2020.

The largest project, Phillips 66’s (44.2% ownership) Gray Oak pipeline, has a design capacity of 900,000 bbl/d and is expected to be in service by the end of 2019. The pipeline will serve multiple Texas Gulf Coast destinations, including Corpus Christi, where it will connect to the South Texas Gateway Terminal. This marine terminal is located at the mouth of Corpus Christi Bay and is under construction by Buckeye Partners. It will have two deepwater docks with initial storage capacity of about 7 MMbbl and up to 800,000 bbl/d of throughput capacity. In addition to the South Texas Terminal, Gray Oak also will service Phillip 66’s refinery in Sweeny, Texas, and the Houston markets.

Much of the increasing Permian crude is destined for the Texas Gulf Coast, where it is being exported to foreign markets. The importance of the export market for Permian crude cannot be overstated. Permian crude quality is from light to intermediate oil, and U.S. refineries are largely designed to process heavier crudes—a legacy issue from when the U.S. relied on imported crude for refinery input (Figure 8).

 

 

 

 

 

Until recently, China was the largest recipient of U.S. crude oil exports. Since July 2018, while U.S. exports continue to grow, China has decreased its U.S. crude imports substantially. The rest of the world has taken up the slack of China’s volumes with notable increases in both Korea and India.

Turning to Permian gas, associated gas production is rising rapidly as oil production ramps up. Current production of 10.5 Bcf/d exceeds the stated 8 Bcf/d of pipeline takeaway capacity (Figure 9).

 

 

 

This bottleneck will be partially relieved with Kinder Morgan’s 1.9-Bcf/d Gulf Coast Express, which runs from the Waha Hub to the Agua Dulce Hub area in Texas’ southern Gulf Coast. Gulf Coast Express began line pack in mid-July 2019 and is expected to be in full service by September 2019. News of the line pack dramatically moved Waha cash gas prices from essentially $0.00 to about $1.20/MMBtu.

Beyond this relief, Kinder Morgan’s next major gas pipeline, the Permian Highway, is expected to bring another 2 Bcf/d of Permian gas takeaway beginning in October 2020, which will push Permian gas takeaway to 11.9 Bcf/d. This will result in a temporary excess capacity of about 0.8 Bcf/d assuming Enverus Drillinginfo’s base forecast.

Like oil, most of this new Permian gas takeaway capacity is headed toward Corpus Christi. The ultimate destination is largely for LNG export. In broader terms, growing LNG export capacity is the relief valve for increasing U.S. gas production. From a zero starting point beginning in early 2016, LNG stated capacity has now grown to 5 Bcf/d from four facilities: Sabine Pass, Louisiana (Cheniere), Cameron, Louisiana (consortium of Sempra, Mitsui, Mitsubishi, Total and NYK Line), Cove Point, Maryland (Dominion Energy) and the latest in Corpus Christi (Cheniere).

Role of M&A in the Permian and the case for consolidation
Since 2015, the Permian has by far been the most active area in the U.S. for M&A activity and accounts for $98 billion of the $340 billion U.S. upstream M&A market. The $98 billion figure does exclude large transactions that cross multiple plays, such as Occidental’s recent $57 billion purchase of Anadarko Petroleum, the largest deal of this time frame. Also excluded is BP’s $10.5 billion buy of BHP’s U.S. shale portfolio in July 2018.

Remarkably, of the $98 billion spent for deals in the Permian since 2015, 70% of those dollars, or $69 billion, was allocated to the purchase of land. Breaking down the $69 billion spent on land inventory even further, $41 billion of that figure was spent in the Delaware Basin, $26 billion in the Midland Basin and the remaining $2 billion spread across both areas.

Figures 10a and 10b show some of the recent $300 million-plus deals in each of the Delaware and Midland basins since 2017. The background green shapes are each basin’s tiered acreage rated from high to low based on Enverus’ analysis of well-level economics.

 

 

 

The money spent for inventory in the Delaware Basin opened the area to reach new heights. The biggest bet to date in the Delaware Basin stems from the recent battle between Occidental and Chevron for Anadarko Petroleum. This $57 billion win by Occidental solidified its production leadership position in the Permian and, according to Enverus Drillinginfo’s analysis, $14 billion of that number was paid for the Delaware Basin acreage position. The next two largest bets placed were Diamondback’s $9.2 billion buy of Energen (August 2018, $5.7 billion for land) and Exxon Mobil’s $5.6 billion buy of Yates Petroleum (November 2017, $5 billion for land).

On the Midland side of the Permian, the two largest bets were Concho Resources’ $9.5 billion buy of RSP Permian (March 2018, $7 billion for land) and Parsley Energy’s $2.8 billion buy of Double Eagle Petroleum (February 2017, $2.6 billion for land).

Chevron’s desire to expand in the Permian had its limits, as seen in its withdrawal from the Anadarko Petroleum battle, but it certainly signaled the allure of the Permian to major oil companies that for the most part have yet to make transformational moves. Certainly, BP’s entry into the Permian, Eagle Ford and Haynesville with its $10.5 billion buy of BHP’s legacy U.S. resource portfolio and Exxon Mobil’s $5.6 billion buy of Yates Petroleum were significant. But there is no doubt that the major oil companies have additional firepower and desire to expand their Permian presence.

The fact that, as shown earlier in this article, Exxon Mobil is by far the leading driller in the Permian with 52 rigs running and a 68% production growth rate between March 2018 and March 2019 speaks volumes as to major oil companies’ sights for the future. There is a strong likelihood that this theme applies to most of the other majors, certainly Chevron.

The Permian is primed for consolidation as the size of the prize is large. As the industry has demonstrated, there are many variables to achieving top-tier economic results in the Permian. Owning the best portions of the rocks ranks highest. Operational scale and consistency also matter. Blocking up acreage to drill 10,000-ft or longer laterals matters.

Majors rank among the top candidates to become consolidators in today’s markets, particularly given the growing valuation disconnect between their equity and public independent E&P names, not to mention the size of the balance sheet. In addition to public independents, there are also some large private operators that have always been attractive acquisition targets.

Innovation marching ahead
Much is being written today regarding finding optimal spacing within the Permian. As operators are now being graded on profitability (aka “achieving sustainable free cash flow”) versus value growth, the game has changed. Historically, public company operators built their companies with the goal of increasing the NPV of their assets and this, by its nature, drove growth and reinvestment into high return wells. This paradigm shift of the “scorecard” is changing company behavior and will impact development within the Permian.

As an example, Midland Basin leader Pioneer Natural Resources was on a mission to achieve 1 MMboe/d of production by 2026 via reinvestment into the company. Now Pioneer has pivoted to returning cash to shareholders in a meaningful manner while downshifting growth to the mid-teens.

The investment decision for optimal well-level returns versus optimal drainage of the reservoir impacts well-spacing decisions and is depicted in Figure 11.

Collectively as an industry, E&P operators are innovators. Perhaps more than anywhere else, those in the Permian Basin have proven this by virtue of the great advances made after the November 2014 oil price crash. Instead of retreating, the industry innovated.

There are many examples of well-level economics that are higher today at $55 or $60/bbl oil then when oil prices were north of $90/bbl. These advances in cost efficiencies and reservoir optimization speak volumes to the ultimate potential of the Permian Basin. And there is more to come.

In early August, when posed a question by an analyst if there were more efficiencies in drilling and completion costs to be had in the Permian, Diamondback CEO Travis Stice answered with a baseball analogy: The Midland Basin is “getting into inning six” while the Delaware Basin is in “inning three or four.” We are still learning.

But innovation and improvements require calculated risk taking. Only from trial and error, can the industry advance the ball for the benefit of all operators.

Recently, Concho Resources’ stock price got knocked down severely due to less than expected results from its Dominator spacing test project in Lea County, N.M., as the company pushed the envelope in search of optimal spacing. Located in an ideal area for the development test, operationally the company performed superbly. The project required the simultaneously use of seven rigs to drill 23 wells in some of the densest spacing the company has undertaken. The results indicated that the spacing was too tight.

To dive a bit deeper, Concho’s Dominator project in the Wolfcamp A bench in Lea County had a combined average well spacing of 230 ft versus a Lea County average of 600 ft (Figure 12). The location for this project is a top-performing area with greater than 80% IRRs based on type-curve economics at $50 oil (Figure 13). Furthermore, Concho had past success downspacing in Lea County.

 

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part 2

 

Southwest of Dominator, Concho had previously brought on a successful nine-well program drilled in 2018 on 545-ft horizontal spacing. Direct offset operators on the Dominator location had also further downspaced. So Dominator was a calculated test to logically push the limits of increased well density. 

Despite the hit on Concho’s stock price, operators should be encouraged to continue to test the boundaries of optimal spacing. It is only through these tests that Permian operators collectively can optimize the reservoirs and maximize profits for company owners.

It is just this kind of prudent risk-taking that advances the ball for all within the Permian. Concho will be a better company for the learnings from Dominator. While Wall Street investors may react, sometimes overreact, there remains little doubt that efficiencies in the Permian continue to improve and the economics will reflect these gains.

Conclusion
The forecast for the Permian is brighter than ever. From a supply point of view, the basin will lead all other areas in the U.S. in production growth in the short, mid and long term. Enverus Drillinginfo forecasts Permian oil production growth to slow a bit in 2019 to an average 12.3 MMbbl/d with growth continuing but at a slower pace thereafter. Enverus Drillinginfo forecasts Permian oil production to reach 15.5 MMbbl/d by 2023 and 17.9 MMbbl/d by 2029. For gas, the Permian will match the Northeast for production growth, with each adding 2.2 Bcf/d in the next five years. Long-haul takeaway capacity for Permian gas remains at a shortage with this not being resolved until late 2020. 

Underpinning the strong outlook for the Permian is a large swath of land that has proven half-cycle well-level economics profitable at prices well below $50 WTI.

Enverus Drillinginfo expects this bright outlook for the Permian to attract the world’s largest companies to expand their positions. Certainly Chevron’s recent bid for Anadarko Petroleum is a strong signal. Exxon Mobil is the largest driller in the basin. BP recently entered the Permian via its BHP buy. The case for consolidation remains strong underpinnned by the strong economic benefits of scale and control of blocky acreage for long laterals. These factors favor major oil and super independents to be the consolidators.

Innovation in the Permian has and will continue to thrive. The industry is testing the limits on well spacing and the learnings will lead to more accurate assessment of inventory and the timing and magnitude of investment decisions.

The recent pivot of operators to a free cash flow model will impact the pace of Permian growth as companies look to distribute cash back to shareholders as opposed to reinvesting in high rate of return projects. 

On the global stage, growing Permian production is of paramount importance when evaluating supply and demand and developing an oil price outlook. The bright Permian outlook is a large factor that drives the current longer term price forecast of $55 WTI, with shocks significantly above or below this likely to prove transitory.

(All charts are courtesy of Enverus Drillinginfo)

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1 minute ago, ceo_energemsier said:

part 1

 

 

Permian Poised To Deliver Strong Oil And Gas Production Growth

 

This article focuses on the outlook for the Permian Basin, which will continue to grow beyond 2029 driven by its large aerial extent of economic drilling at oil prices of less than $50 WTI. Rig count trends, top operators, midstream buildout, merger and acquisition (M&A) activity and a topical discussion on well spacing are presented.

After supporting Permian operators to spend vast sums of money during 2016 and 2017 to buy land inventory, Wall Street shifted its scorecard on the industry from one of a discounted cash flow or net present value (NPV) approach to one predicated on demonstrating sustainable free cash flow to return to shareholders. This paradigm shift from Wall Street has been abrupt, and public E&P executives hear the message and are pivoting business strategies. Given the nature of the industry, the pivot will take some time but is well underway. This will impact the rate of growth in the Permian as less capital is put into the ground. But the basin supply dynamics remain strong. The Wall Street sentiment to E&P companies is currently negative, but industry innovation continues strong and more efficiencies are on the way. Enverus Drillinginfo is confident Permian Basin economics are strong enough to both grow production and return cash to shareholders. At some point, Wall Street sentiment is expected to shift back and support the great advances many companies are making.

Production forecast
Enverus Drillinginfo forecasts U.S. oil production to grow by 1.5 MMbbl/d in 2019 to an average of 12.3 MMbbl/d, an increase of 13% over 2018. This is moderated from the 2018 record growth of 17%, or 1.6 MMbbl/d. From 2020 to 2023, production growth will continue to moderate and increase by another 3.2 MMbbl/d (or an average 6%) to reach 15.5 MMbbl/d in 2023 (Figure 1).

 

 

The Permian Basin leads U.S. oil growth and accounted for 1 MMbbl/d, or 62%, of the record 2018 growth. The Permian will continue to lead and is forecast to grow by another 0.8 MMbbl/d in 2019 to an average 4.3 MMbbl/d. By 2023, Permian production is forecast to average 5.7 MMbbl/d.

In 10 years U.S. production is expected to reach about 17.3 MMbbl/d, at which time the Permian will account for 40% (or 6.8 MMbbl/d) of U.S. production—up from its 35% share this year. Longer term, the Permian will continue to grow beyond 2029, which is forecast to underpin a flattening U.S. oil production profile.

For U.S. gas, growth also continues. Although, like oil, it is at a slower pace from recent history. From 2015 to 2019, gas production grew by 14.8 Bcf/d to reach a forecast average of 88.8 Bcf/d in 2019. Growth will slow by nearly 60% to add another 6.4 Bcf/d by 2024. The Permian and the Northeast will contribute equally to the growth at 2.2 Bcf/d during the next five years (Figure 2).

 

 

 

 

Well-level economics driving growth
This growth in U.S. oil production is driven by substantial swaths of land that are currently de-risked and economic at prices of $55 WTI or less. While the Permian accounts for much of this profitable drilling inventory, portions of virtually all other major resource plays contribute to this growth, including the Bakken and Eagle Ford.

Based on a bottoms-up methodology, Enverus Drillinginfo maintains well economics on more than 200 distinct groupings of areas predicated on well history and current cost economics. Shown in Figure 3 are breakeven economics for oil. There is a substantial inventory that is profitable based on half-cycle (driven by drill and complete costs) economics at oil prices less than $50 with a minimum return threshold of 12.5% (Figure 3). The second key takeaway from the breakeven analysis is the continuum of plays that become economic as oil prices rise. The “Plays on the Margin” noted in Figure 3 become economic at a WTI price of between $50 and $65.

 

 

 

In aerial extent, the Permian’s Wolfcamp, Spraberry and Bone Spring formations lead the inventory counts of drillable economic locations. Within the Permian, the top tiers of these formations lie in the Delaware Basin with breakeven economics of less than $33/bbl. Average Delaware Basin breakevens are $39/bbl, while in the Midland Basin the northern section rivals the Delaware while the southern section remains challenged at $50 WTI (Figure 4). 

Other leading areas outside of the Permian include the top areas in the Eagle Ford such as DeWitt County, Texas, and the Sugarkane area of Karnes County, Texas. The Antelope area of the Williston Basin also is leader in the race for breakeven economics. 

 

 

 

Permian top operators
With its transformational $57 billion buy of Anadarko Petroleum, which closed Aug. 8, Occidental Petroleum extended its lead as the top Permian oil producer, currently accounting for more than 10% of the basin’s gross operated production and more than 50% ahead of the second largest producer, Concho Resources. 

Figure 5 shows the top 15 producers in the Permian that collectively operate 57% of the oil production. Enverus Drillinginfo notes a long tail of smaller operators. Currently, there are more than 300 companies operating in the Permian that produce 100 bbl/d or more.

Noteworthy is that the share of the top 15 has remained consistent since 2017 at 57%. The collective growth rate for this group dropped from 38% in March 2017-2018 to 27% in March 2018-2019. Perhaps more striking is that over this two-year period, the top 15 grew production by a striking 76%.

Certainly, as companies get larger, they have performed admirably with growing production. Growing from a large base of production presents a complex set of business and operational issues. As time marches on, these large operators continue to find business process improvements that positively affect cost structure and consistency.

 

 

 

 

It is in this time frame that the Permian rebirth started in earnest, driven in large part by the opening of the Delaware Basin. From that trough in April 2016, the Permian rig count consistently rose by nearly 400% over 2.5 years to reach a recent peak of 505 on Nov. 16, 2018, at which time its share of the U.S. rig count rose to 42%. It is this trough to peak rig activity that spurred the record Permian production growth in 2018, which is continuing into 2019.

Recently since its peak of 505 in November 2018, Permian rig counts have declined by about 15%, which is setting up for a slower production growth rate in 2019 and beyond. The correlation between rig counts and production, while largely directionally consistent, are not directly correlated as operators are continuously innovating and moving toward drilling longer laterals and improving drill times. Regarding drill times, thus far in 2019, average spud to release is 19 days, an improvement from an average 21 days in 2014.

Permian oil takeaway forecast
As Permian oil production was rapidly ramping, midstream operators moved in quickly to begin building additional long-haul capacity directed to the Texas Gulf Coast export markets (Figure 7).

 

 

 

 

 

Capacity out of the Permian is expected to increase by 2.1 MMbbl/d this year. Plains All American’s Cactus II pipeline, originating in Wink, Texas, and terminating in Corpus Christi, Texas, with a 650,000-bbl/d design capacity, is complete and has begun commercial operations, with full service to Corpus Christi expected by the end of the first quarter of 2020.

The largest project, Phillips 66’s (44.2% ownership) Gray Oak pipeline, has a design capacity of 900,000 bbl/d and is expected to be in service by the end of 2019. The pipeline will serve multiple Texas Gulf Coast destinations, including Corpus Christi, where it will connect to the South Texas Gateway Terminal. This marine terminal is located at the mouth of Corpus Christi Bay and is under construction by Buckeye Partners. It will have two deepwater docks with initial storage capacity of about 7 MMbbl and up to 800,000 bbl/d of throughput capacity. In addition to the South Texas Terminal, Gray Oak also will service Phillip 66’s refinery in Sweeny, Texas, and the Houston markets.

Much of the increasing Permian crude is destined for the Texas Gulf Coast, where it is being exported to foreign markets. The importance of the export market for Permian crude cannot be overstated. Permian crude quality is from light to intermediate oil, and U.S. refineries are largely designed to process heavier crudes—a legacy issue from when the U.S. relied on imported crude for refinery input (Figure 8).

 

 

 

 

 

Until recently, China was the largest recipient of U.S. crude oil exports. Since July 2018, while U.S. exports continue to grow, China has decreased its U.S. crude imports substantially. The rest of the world has taken up the slack of China’s volumes with notable increases in both Korea and India.

Turning to Permian gas, associated gas production is rising rapidly as oil production ramps up. Current production of 10.5 Bcf/d exceeds the stated 8 Bcf/d of pipeline takeaway capacity (Figure 9).

 

 

 

This bottleneck will be partially relieved with Kinder Morgan’s 1.9-Bcf/d Gulf Coast Express, which runs from the Waha Hub to the Agua Dulce Hub area in Texas’ southern Gulf Coast. Gulf Coast Express began line pack in mid-July 2019 and is expected to be in full service by September 2019. News of the line pack dramatically moved Waha cash gas prices from essentially $0.00 to about $1.20/MMBtu.

Beyond this relief, Kinder Morgan’s next major gas pipeline, the Permian Highway, is expected to bring another 2 Bcf/d of Permian gas takeaway beginning in October 2020, which will push Permian gas takeaway to 11.9 Bcf/d. This will result in a temporary excess capacity of about 0.8 Bcf/d assuming Enverus Drillinginfo’s base forecast.

Like oil, most of this new Permian gas takeaway capacity is headed toward Corpus Christi. The ultimate destination is largely for LNG export. In broader terms, growing LNG export capacity is the relief valve for increasing U.S. gas production. From a zero starting point beginning in early 2016, LNG stated capacity has now grown to 5 Bcf/d from four facilities: Sabine Pass, Louisiana (Cheniere), Cameron, Louisiana (consortium of Sempra, Mitsui, Mitsubishi, Total and NYK Line), Cove Point, Maryland (Dominion Energy) and the latest in Corpus Christi (Cheniere).

Role of M&A in the Permian and the case for consolidation
Since 2015, the Permian has by far been the most active area in the U.S. for M&A activity and accounts for $98 billion of the $340 billion U.S. upstream M&A market. The $98 billion figure does exclude large transactions that cross multiple plays, such as Occidental’s recent $57 billion purchase of Anadarko Petroleum, the largest deal of this time frame. Also excluded is BP’s $10.5 billion buy of BHP’s U.S. shale portfolio in July 2018.

Remarkably, of the $98 billion spent for deals in the Permian since 2015, 70% of those dollars, or $69 billion, was allocated to the purchase of land. Breaking down the $69 billion spent on land inventory even further, $41 billion of that figure was spent in the Delaware Basin, $26 billion in the Midland Basin and the remaining $2 billion spread across both areas.

Figures 10a and 10b show some of the recent $300 million-plus deals in each of the Delaware and Midland basins since 2017. The background green shapes are each basin’s tiered acreage rated from high to low based on Enverus’ analysis of well-level economics.

 

 

 

The money spent for inventory in the Delaware Basin opened the area to reach new heights. The biggest bet to date in the Delaware Basin stems from the recent battle between Occidental and Chevron for Anadarko Petroleum. This $57 billion win by Occidental solidified its production leadership position in the Permian and, according to Enverus Drillinginfo’s analysis, $14 billion of that number was paid for the Delaware Basin acreage position. The next two largest bets placed were Diamondback’s $9.2 billion buy of Energen (August 2018, $5.7 billion for land) and Exxon Mobil’s $5.6 billion buy of Yates Petroleum (November 2017, $5 billion for land).

On the Midland side of the Permian, the two largest bets were Concho Resources’ $9.5 billion buy of RSP Permian (March 2018, $7 billion for land) and Parsley Energy’s $2.8 billion buy of Double Eagle Petroleum (February 2017, $2.6 billion for land).

Chevron’s desire to expand in the Permian had its limits, as seen in its withdrawal from the Anadarko Petroleum battle, but it certainly signaled the allure of the Permian to major oil companies that for the most part have yet to make transformational moves. Certainly, BP’s entry into the Permian, Eagle Ford and Haynesville with its $10.5 billion buy of BHP’s legacy U.S. resource portfolio and Exxon Mobil’s $5.6 billion buy of Yates Petroleum were significant. But there is no doubt that the major oil companies have additional firepower and desire to expand their Permian presence.

The fact that, as shown earlier in this article, Exxon Mobil is by far the leading driller in the Permian with 52 rigs running and a 68% production growth rate between March 2018 and March 2019 speaks volumes as to major oil companies’ sights for the future. There is a strong likelihood that this theme applies to most of the other majors, certainly Chevron.

The Permian is primed for consolidation as the size of the prize is large. As the industry has demonstrated, there are many variables to achieving top-tier economic results in the Permian. Owning the best portions of the rocks ranks highest. Operational scale and consistency also matter. Blocking up acreage to drill 10,000-ft or longer laterals matters.

Majors rank among the top candidates to become consolidators in today’s markets, particularly given the growing valuation disconnect between their equity and public independent E&P names, not to mention the size of the balance sheet. In addition to public independents, there are also some large private operators that have always been attractive acquisition targets.

Innovation marching ahead
Much is being written today regarding finding optimal spacing within the Permian. As operators are now being graded on profitability (aka “achieving sustainable free cash flow”) versus value growth, the game has changed. Historically, public company operators built their companies with the goal of increasing the NPV of their assets and this, by its nature, drove growth and reinvestment into high return wells. This paradigm shift of the “scorecard” is changing company behavior and will impact development within the Permian.

As an example, Midland Basin leader Pioneer Natural Resources was on a mission to achieve 1 MMboe/d of production by 2026 via reinvestment into the company. Now Pioneer has pivoted to returning cash to shareholders in a meaningful manner while downshifting growth to the mid-teens.

The investment decision for optimal well-level returns versus optimal drainage of the reservoir impacts well-spacing decisions and is depicted in Figure 11.

Collectively as an industry, E&P operators are innovators. Perhaps more than anywhere else, those in the Permian Basin have proven this by virtue of the great advances made after the November 2014 oil price crash. Instead of retreating, the industry innovated.

There are many examples of well-level economics that are higher today at $55 or $60/bbl oil then when oil prices were north of $90/bbl. These advances in cost efficiencies and reservoir optimization speak volumes to the ultimate potential of the Permian Basin. And there is more to come.

In early August, when posed a question by an analyst if there were more efficiencies in drilling and completion costs to be had in the Permian, Diamondback CEO Travis Stice answered with a baseball analogy: The Midland Basin is “getting into inning six” while the Delaware Basin is in “inning three or four.” We are still learning.

But innovation and improvements require calculated risk taking. Only from trial and error, can the industry advance the ball for the benefit of all operators.

Recently, Concho Resources’ stock price got knocked down severely due to less than expected results from its Dominator spacing test project in Lea County, N.M., as the company pushed the envelope in search of optimal spacing. Located in an ideal area for the development test, operationally the company performed superbly. The project required the simultaneously use of seven rigs to drill 23 wells in some of the densest spacing the company has undertaken. The results indicated that the spacing was too tight.

To dive a bit deeper, Concho’s Dominator project in the Wolfcamp A bench in Lea County had a combined average well spacing of 230 ft versus a Lea County average of 600 ft (Figure 12). The location for this project is a top-performing area with greater than 80% IRRs based on type-curve economics at $50 oil (Figure 13). Furthermore, Concho had past success downspacing in Lea County.

 

 

[ceo_energemsier + 1,818]

Strong gas production in Shale Crescent region led to $1.1 trillion in savings

American gas end-users have realized $1.1 trillion in savings since 2008 as a result of increased gas production in the Shale Crescent USA region (Ohio, Pennsylvania, and West Virginia), according to a new economic analysis released Oct. 21.

 

Oct 21st, 2019

American natural gas end-users—which include households, businesses, manufacturers, and power generators—have realized $1.1 trillion in savings since 2008 as a result of increased gas production in the Shale Crescent USA region (Ohio, Pennsylvania, and West Virginia), according to a new economic analysis released Oct. 21.

The report—Natural Gas Savings to End-Users: 2008-18, A Technical Briefing Paper, released by Shale Crescent USA (SCUSA) and the Ohio Oil & Gas Energy Education Program (OOGEEP)—found that the substantial growth in US gas production resulted in more than $4,000/household in savings over the 10-year period for those that use gas.

US gas producers, employing advanced technologies, have made the US the top gas-producing country in the world, with 85% of that growth coming from the Shale Crescent region.

Tied directly to the abundance of affordable gas, residential, commercial, industrial, and electric power generating sectors in these three states have realized a combined savings of more than $90 billion since 2009 (Ohio, $45 billion; Pennsylvania, $44 billion; and West Virginia, $4 billion).

Industrial users in Shale Crescent region have realized nearly $25 billion in savings over the past 10 years, increasing the attractiveness for new manufacturing investments—a conclusion that aligns with the findings of previous studies conducted by IHS Markit for Shale Crescent USA. Energy-intensive industries that locate in the Shale Crescent region, according to the IHS Markit studies, should experience markedly higher profits than other areas of the country due to lower gas and natural gas liquids prices.

“The strength of natural gas and natural gas liquids production in the Shale Crescent region, as this report confirms, has made this region the most profitable place to build a petrochemical plant, giving manufacturers here a critical competitive edge,” said Shale Crescent USA co-founder Jerry James. “Energy is the catalyst to breathing new life into American manufacturing and, after years of challenges, we are excited about the bright future in store for communities all along the Shale Crescent.”

Development of the Marcellus and Utica shale formations in these states is responsible for one third of the nation’s gas production, and recent projections show the region will account for nearly 45% by 2040.

“The surge of affordable, reliable energy had an incredibly positive impact on our operations. The natural gas savings we realized were the driving force in reducing operating costs, which allowed Eagle to expand our workforce and grow as a company,” said Joe Eddy, former president and chief executive officer of Eagle Manufacturing, which produces more than 750 products from their Wellsburg, West Virginia site.

In addition to attracting new industry and the corresponding rise in job creation, the report demonstrates the dramatic energy savings delivered to residential consumers across the country. Low-income households experience some of the most significant savings, with energy bills for the lowest 20% of incomes, dropping by 30%, or $315, since 2008. This would be similar to a 2.7% boost in annual income.

 

“If Ohio, Pennsylvania, and West Virginia were a country, it would be the world’s third largest natural gas producer—an accomplishment due to technology innovation that is unlocking energy from the Marcellus and Utica shales, and resulting in growth across the region,” said Rhonda Reda, executive director of the Ohio Oil & Gas Energy Education Program. “The savings tied to Ohio natural gas production have been transformational for all energy consumers, particularly for low-income families who spend a disproportionate amount on energy,” she said.

[ceo_energemsier + 1,818]

Over the past decade, the U.S. oil and gas sector has emphasized developing short-cycle-time unconventional projects rather than wildcat drilling that targets potentially more bountiful conventional plays.

In a recent report, IHS Markit concludes the trend toward unconventional projects has caused the number of conventional discoveries to plunge to a 70-year low. As this chart from IHS Markit shows, the number of conventional new field wildcat (NFW) appraisal and development wells outside Onshore U.S. and Canada lagged behind the number of U.S. unconventional wells from 2013 to 2018 save for two years.

Although unconventional projects give oil and gas firms more flexibility in responding to market changes, the wide disparity in depletion rates between unconventional and conventional wells could become particularly evident in years to come given the shortfall in conventional reserves additions.

“You’re taking from the future and getting immediate gratification,” Keith King, senior advisor with IHS Markit and lead author of the report, told Rigzone. “You’re producing more over a shorter time period and less over a longer time period.”

To illustrate, King explained that an unconventional oil well might experience a 60-percent depletion rate in its first year of production. In contrast, the depletion rate for a conventional well during the same period might be just 12 percent.

“You get all those volumes up front with your investment whereas a conventional well’s production will plateau for, say, 20 years or more,” he continued. “Some conventional wells will produce for 100 years.”

King added the mid-21^st century does not reflect a particularly long time horizon for a conventional oil well.

“Twenty or thirty years into the future might sound like a long time away, but in the conventional world that is not a long time away,” he said. “Conventional wells not being drilled now won’t be producing later on.”

King pointed out that such a scenario makes sense, assuming that a pair of conditions are met.

“What’s strange about that is, in a world with peak demand and where renewables displace fossil fuels, it would be a rational decision – if you believe in peak demand,” he said, adding the world would be short of oil if peak demand fails to materialize at mid-century.

An effect of cheap debt

Tom McNulty, Houston-based managing director with Great American Group, remarked the shift to unconventional “factory drilling” at the expense of conventional development stems primarily from investors gaining access to plentiful debt capital to finance projects.

“The tight-rock, unconventional plays are perfect for a fast-in, fast-out mentality, given their rapid and steep decline curves,” said McNulty.

He noted how the federal government’s response to the “massive credit crisis” toward the end of the previous decade encouraged the investment community to back such projects.

“The government opened up the spigots, ensuring that the economy stayed sound with liquidity and cheap money,” McNulty continued. “Lots and lots of capital became available to fund the ‘Shale Revolution,’ and it was not really all that expensive from a historical perspective. We saw lots of management teams get funded, and lots of private independents got funded, too. Lots of debt capital made it easy to drive up equity returns.”

Watching the story unfold and waiting, “just like a tiger stalking its prey,” were the major operating companies, McNulty added. He observed that the strategy of seeking quick returns from unconventional projects worked fine for smaller players early on – until commodity prices collapsed in the middle of the current decade. To be sure, he added that some small players managed to avoid the “bloodshed” that ensued.

“I think it’s important to differentiate between what ‘Wall Street’ means and what local private capital means,” McNulty said. “I am well aware of several private capital firms that are here in Houston, and in other locations that are not spelled ‘New York,’ that have done very well and have made very smart investments. And, in many other cases, lots of debt became, or will become, call options on cheap equity.”

Then there are the larger exploration and production companies.

“The big majors are entering the unconventional plays with their big balance sheets,” McNulty noted. “The big independents that have managed the right-hand side of their balance sheets well will survive and make acquisitions. The smaller players will survive if they managed their debt well and might be acquired at decent pricing. The smaller players that are over-leveraged will need to go away for good.”

McNulty added that larger, more diversified companies can overcome the large depletion rate disparity between unconventional and conventional oil wells if they manage both types of assets properly.

“The same concepts that we use in portfolio management can be used to diversify timing risk across a package of unconventional oil wells and conventional oil wells,” he explained. “A much better job needs to be done matching the capital structures to the timing of the producing cash flows with potentially weaker prices.”

McNulty also anticipates that conventional projects will increasingly dot the oil and gas development landscape – but not to explicitly counter the instant gratification mindset that has prevailed in the past decade.

“I have had several meetings recently with private companies that are actively working on conventional projects,” he said. “However, I do think that the theme is more about scale and smart capital structures.”

Because larger companies are big, they will more likely include conventional drilling programs in their portfolios, he explained.

“They operate in more places and, in my opinion, will look at both conventional plays and unconventional plays,” he concluded. “I do not agree with the notion that you have to pick one over the other. It will happen as a by-product of consolidation, portfolio diversification and a lower commodity price environment. Lots of debt needs to become equity. Lots of companies need to merge or go away.”

[ceo_energemsier + 1,818]

So, shale naysayers, shale tech..... drum roll...............................

________________________________________________------

 

EOG Boosts Production With EOR Program In Eagle Ford

Research shows the company has been able to yield up to 80% more oil in the Eagle Ford from its gas injection process.

[ceo_energemsier + 1,818]

New Mexico, Texas oil and gas revenues continue spike amid boom in the Permian Basin

 

 

https://www.currentargus.com/story/news/local/2019/10/21/new-mexico-texas-oil-and-gas-revenues-continue-spike-permian-basin/4054037002/

[ceo_energemsier + 1,818]

Bakken looks to add 445 MMcf/d of natural gas processing before year's end

 

 

Should boost flows on Northern Border Pipeline

Will increase gas capture rates

 

Denver — Bakken natural gas production continues to set records and has the potential to surge even more before year's end as more processing capacity comes online, pushing greater volumes to US Midwest markets at the expense of imports from Western Canada.

Daily associated gas production in the oil-oriented patch set production records over three consecutive months this summer, according to the latest data released by the North Dakota Industrial Commission. However, the high volumes produced also led to a massive waste of molecules.

In July, producers flared, or burned off, 670 MMcf/d of natural gas at the wellhead. The primary cause was a lack of adequate gathering lines and/or gas processing capacity in areas where new production is coming online.

However, as production increased 69 MMcf/d month over month to more than 3 Bcf/d in August, operators lowered flaring to 577 MMcf/d. The startup of the Little Missouri IV processing plant likely led to the decline in flaring, according to S&P Global Platts Analytics. Flaring was still high at 19% for the month, well above the state's 12% mandate.

 

 

 

With significant processing capacity coming online by the end of December, to the tune of 445 MMcf/d, producers will likely start to capture and send even more gas to market.

Additional processing capacity will enter service in the Bakken in less than two weeks as Kinder Morgan's Roosevelt processing plant in McKenzie County, North Dakota, nears completion. The project is currently on schedule for an estimated start-up date of November 1. It will provide approximately 150 MMcf/d of incremental processing capacity in the Williston basin once in service.

According to Platts Analytics' NGL Facilities Databank, an additional 295 MMcf/d of processing capacity is expected to enter service before the end of the year with the additions of Oneok's Bear Creek II (95 MMcf/d capacity) and Demicks Lake (200 MMcf/d capacity) processing plants.

The increased processing capacity in North Dakota will likely allow additional supply to displace and squeeze out even more Western Canadian imports along Northern Border pipeline. Year on year, production in the basin has increased by 150 MMcf/d as imports from Western Canada have shrunk by 250 MMcf/d, according to Platts Analytics.

 

[ceo_energemsier + 1,818]

Chevron Sees ‘Boom Boom Boom’ Permian Despite Signs of Slowdown

 

 

Chevron Corp. sees a “boom boom boom kind of economy” in West Texas, shrugging off signs of a Permian Basin slowdown showing up in everything from jobs to hotel rooms.

Steve Green, president of Chevron’s North American business, was insistent that the world’s biggest shale patch won’t be susceptible to historic boom-and-bust cycles that have dominated the Texas oil economy for decades. His booming nod to continuing good times came Tuesday during a panel discussion at the Lone Star Energy Forum in Austin.

“We see a long, healthy pace of activity in the Permian and Texas for decades to come,” Green said at the forum, sponsored by the Texas Oil & Gas Association.

The comments come within days of earnings releases by Schlumberger Ltd. and Halliburton Co., two of the world’s biggest providers of oilfield equipment and services, which detailed an annual drop in North American sales. The companies warned investors that the slowdown could be sharper than an end-of-year slump seen in 2018.

Don Templin, chief financial officer at Marathon Petroleum Corp., who was also on the panel, chimed in on the Texas love fest. But he also added an ominous warning.

The Findlay, Ohio-based refiner has access to global markets and a “good portion” of the 400,000 barrels a day of refined product that it exports is from the gulf coast. But he said investments in export infrastructure will be important in keeping the shale boom moving forward over the next five years.

“Texas plays a really important role,” he said. “But if you don’t have export capabilities, all the product produced in the Permian gets bottlenecked somewhere, and at some point in time, that will dampen the production.”

[Ward Smith + 6,615]

On 10/21/2019 at 11:13 AM, ceo_energemsier said:

US petroleum exports rose to 8.2 million b/d in September from 8.1 million b/d in August. Meanwhile, imports fell by 1 million b/d between August and September to their lowest level for the month since 1993.

Overall US petroleum net imports decreased to 800,000 b/d in September—the second lowest level this year and a step closer to the US becoming a net exporter.

This. Is. Why. The. Oil. World. Is. Nervous. 

[ceo_energemsier + 1,818]

LNG Unites Global Natural Gas Demand

 

http://openmarkets.cmegroup.com/15674/lng-unites-global-natural-gas-demand

 

[ceo_energemsier + 1,818]

The United States now exports crude oil to more destinations than it imports from

 

 

https://www.eia.gov/todayinenergy/detail.php?id=41754

 

[ceo_energemsier + 1,818]

Anti-Shalers_______________ Drum ROLL....

Optimizing shale well designs could boost Eagle Ford and Permian economics

Deloitte’s new research suggests that if Eagle Ford and Permian Basin shale operators were to fully optimize their well designs, they could generate capital efficiency gains of 19% and 23%, respectively.

 

 

 

Deloitte’s new research suggests that if Eagle Ford and Permian Basin shale operators were to fully optimize their well designs, they could generate capital efficiency gains of 19% and 23%, respectively. This could represent a $24 billion capex saving opportunity for US shale operators to strengthen their balance sheets and boost returns.

 

In the report titled “Deciphering the performance puzzle in shales: Moving the shale revolution forward”, Deloitte did a meta-analysis of 80,000 Wells in the Permian and Eagle Ford. The analysis reveals up to 67% of completions in the two regions were either over- or under-engineered. 

“When it comes to efficiency gains, the industry seems presently divided on the outlook for shale wells. Some say gains have peaked, but Deloitte’s deepest foray into well-level data analytics revealed actionable insights which can help improve industry performance at a time when both investor sentiment and commodity prices are low,” said John England, partner, oil, gas and chemicals, Deloitte & Touche LLP.

“The findings clearly show that a one-size-fits-all approach to well design and completions is wasteful, and that it’s time for the industry to choose the right well design, not the biggest, to maximize efficiencies and profitability.” John said.

Key findings

• Rock quality is important but is not necessarily the main performance differentiator. According to Deloitte’s analysis of all drilled wells in the Eagle Ford and Permian, the ranking of acreage (e.g., “Tier 1, Tier 2, Tier 3”) does not influence well performance to the extent previously assumed. More than 40% of wells drilled outside the core of the western Delaware area reported initial 180-day normalized productivity of more than 1,000 barrels of oil equivalent per day (boed). In the Eagle Ford, a comparable number of high-performing wells exist across acreage tiers. 
• "Bigger is also not always better." The statistical analysis further notes wells drilled over the last two to three years, with complex and intense completion designs (i.e., longer laterals, more proppants, etc.) actually led to diminished productivity, explaining some of the concerns from investors and financial markets.
• During this period, more than 3,000 wells that were completed with massive volumes of proppant (in excess of 1,800 pounds per foot) yielded productivity below 750 boed per 10,000 feet of perforated interval. Despite an increase in completion intensity of more than 40%, approximately 50% of US horizontal wells had the normalized 180-day productivity of below 750 boed in the past four years.
• Optimizing well designs can boost capital efficiency. Deloitte found approximately 67% of wells in the Permian have been under- or over-engineered. A more balanced formation-and-engineering equation could improve the capital efficiency of Permian operators by approximately 23%. Similarly, approximately 60% of Eagle Ford wells have been under- or over-engineered. An optimal completion design strategy could increase capital efficiency of Eagle Ford operators by 19%.
• Improving well-designs has the potential for US shale drillers to reduce capital requirements by $24 billion. If achieved, E&Ps could achieve economic targets in a broader range of price scenarios, and thereby revive investor interest, per the analysis.
• Myriad solutions to consider. To succeed, shale companies can utilize more sophisticated data analytics and balance experimentation and standardization. Technology is king, and knowing the reservoir is critical. Therefore, E&Ps should consider investing in advanced technologies such as microseismic monitoring, fluid tracking and tracer analytics, among others, to understand how and why the reservoir is behaving in a certain fashion and then augment the development approach.

Sustaining shale efficiency gains

Optimizing well designs is an important priority, but the industry shouldn’t stop there, Deloitte notes.

To make truly sustainable improvements and build resiliency against future price cycles, operators should work with all stakeholders in the oil and gas ecosystem. For example, E&Ps should co-share the productivity benefits with oilfield service companies, and design new win-win contractual arrangements with infrastructure providers.

Importantly, E&Ps should also win back investors’ trust through more consistent transparency and reporting details of performance. Companies should standardize how they report well results and look to third parties to help. Large institutional investors, energy agencies, and shale industry associations along with data aggregators could play a big role in standardizing performance benchmarks for the shale industry and its investors.  

“Even though we’re over 10 years into the shale era, the industry is actually in the early stages of understanding. As with any new resource, the early phase of growth is also the initial phase of evolution and experimentation,” said Scott Sanderson, principal, Deloitte LLP’s oil and gas strategy and operations practice. “Now we are more aware of the challenges facing the viability of shales, and ‘brute force’ is not necessarily the answer. E&Ps should use analytic insights like this to course-correct both operational tasks and commercial arrangements to bring sustainable benefits to shareholders and the extended oil and gas ecosystem.”

 

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Edited October 23, 2019 by ceo_energemsier

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Mubadala Investment Co., the Abu Dhabi government-owned sovereign wealth fund, has agreed to purchase $50 million of NextDecade Corp’s common stock in a private placement, the companies reported Thursday.

NextDecade, which is developing the Rio Grande LNG export project in Brownsville, Texas, will issue the common stock to Mubadala at a price of $6.27 per share, according to a joint written statement from the firms.

“We are honored to welcome Mubadala, a leading global investor, as a shareholder in our company,” NextDecade Chairman and CEO Matt Schatzman commented. “Mubadala brings a valuable perspective on large-scale infrastructure investment and the growing role of LNG in the Middle East and other markets around the world. We look forward to a strong and lasting partnership.”

In conjunction with the deal, the companies also stated that Mubadala will receive a seat on NextDecade’s board of directors. Also, Mubadala – whose global investment portfolio across various industries totals $229 billion – will be able to contribute project-level capital upon the Rio Grande LNG final investment decision.

“We strongly believe that the Rio Grande LNG project is optimally positioned to provide a highly competitive export route for the abundant gas resources of the Permian Basin and a compelling commercial proposition for LNG customers, Permian producers and NextDecade shareholders alike,” noted Khalifa Al Romaithi, Mubadala’s midstream executive director. “Our investment also reflects Mubadala’s positive outlook on the global gas market and the growing role of gas in the energy transition.”

As Rigzone reported in May 2018, the Rio Grande project would take in associated natural gas shipped from the Permian Basin. The 27-million-ton-per-annum, six-train Rio Grande LNG export terminal in the Port of Brownsville would receive gas via the Rio Bravo Pipeline. The pipeline – a project NextDecade is developing with Enbridge Inc. – would deliver up to 4.5 billion cubic feet per day of Permian and Eagle Ford Shale gas from the Agua Dulce supply area near Corpus Christi. In May of this year, Rigzone also reported that Bechtel Oil, Gas and Chemicals won Rio Grande LNG engineering, procurement and construction contracts worth more than $9.5 billion.

According to a timeline NextDecade’s website, a final investment decision on the project should occur in the first quarter of 2020.