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The break-even price for Permian basin tight oil plays is about $61 per barrel. That puts Permian plays among the lowest cost significant supply sources in the world. Although that is good news for U.S. tight oil plays, there is a dark side to the story.

Just because tight oil is low-cost compared to other expensive sources of oil doesn’t mean that it is cheap. Nor is it commercial at current oil prices.

The disturbing truth is that the real cost of oil production has doubled since the 1990s. That is very bad news for the global economy. Those who believe that technology is always the answer need to think about that.

Through that lens, Permian basin tight oil plays are the best of a bad, expensive lot.

Not Shale Plays and Not New

The tight oil plays in the Permian basin are not shale plays. Spraberry and Bone Spring reservoirs are mostly sandstones and Wolfcamp reservoirs are mostly limestones.

Nor are they new plays. All have produced oil and gas for decades from vertically drilled wells. Reservoirs are commonly laterally discontinuous and, therefore, had poor well performance. Horizontal drilling and hydraulic fracturing have largely addressed those issues at drilling and completion costs of $6-7 million per well.

Permian Basin Overview

The Permian basin is among the most mature producing areas in the world. It has produced more than 31.5 billion barrels of oil and 112 trillion cubic feet of gas since 1921. Current production is approximately 1.9 million barrels of oil (mmbo) and 6.6 billion cubic feet of gas (bcfg) per day.

The Permian basin is located in west Texas and southeastern New Mexico. It is sub-divided into the Midland basin on the east and the Delaware basin on the west, separated by the Central Basin platform.

The first commercial discovery in the Permian basin was made in 1921 at the Westbrook Field. It was followed in 1926 with the 2 billion barrel (bbo) Yates Field (San Andres & Grayburg reservoirs), the 2.1 bbo Wasson Field (Glorieta and Leonard reservoirs) in 1936, and the 1.5 bbo Slaughter Field (Abo and Clear Fork reservoirs) also in 1936. Reservoirs were chiefly high-quality limestones although the Wasson and Slaughter fields also produced from mixed sandstones and limestones that are equivalent to reservoirs in today’s Bone Springs tight oil play.

The Spraberry Field (1949) was the first discovery whose primary reservoir was among the present tight oil plays. Its ultimate production before horizontal drilling was estimated at 932 mmbo. The field had low recovery efficiency of 8-10% and was only marginally commercial prior to the recent phase of tight oil drilling.

Tight Oil Plays

I evaluated the three main tight oil plays.  The Trend Area-Spraberry play is located mostly in the Midland basin while the Wolfcamp and Bone Spring plays are located mainly in the Delaware basin.

The Wolfcamp play has produced the most oil and gas—205 million barrels of oil equivalent (mmBOE)*—and has the largest number of producing wells, followed by the Trend Area-Spraberry and Bone Spring plays. All of the plays produce considerable associated gas and only the Trend Area-Spraberry is technically an oil play. The Wolfcamp and Bone Spring are classified as gas-condensate plays based on liquid yield.

The Bone Spring play is the most commercially attractive of the tight oil plays with an estimated $49 per barrel of oil equivalent (BOE) break-even price for the top 5 operators. The Spraberry play has a break-even price of $55 per BOE for the top 5 operators but considerably higher well density and, therefore, lower long-term potential. Results from the Wolfcamp play are mixed with an average break-even price of $75 per BOE for the top 5 operators but $61 per BOE excluding one operator with poorer well performance.

Trend Area-Spraberry Play

I evaluated the 5 key operators in the Trend Area-Spraberry play with the greatest cumulative production and number of producing wells: Pioneer (PXD), Laredo (LPI), Diamondback (FANG), Apache (APA) and Energen (EGN).

I did standard rate vs. time decline-curve analysis for those operators. The matches with production history were generally good.

Much of the gas production in the Permian basin is irregular because of periodic flaring so matching gas production history was sometimes difficult. Oil reporting in Texas is by lease rather than by well so there are periodic upward excursions of oil production as new wells on the same lease come on line. For these reasons, I feel that the decline-curve analysis results are probably optimistic.

The average Trend Area-Spraberry well EUR (estimated ultimate recovery) for the 5 operators is approximately 265,000 BOE using an economic value-based conversion of natural gas-to-barrels of oil equivalent of 15-to-1. The break-even oil price for that average EUR is approximately $55 per BOE. Laredo has the best average well performance with a break-even oil price of about $43 per BOE and Apache has the poorest well performance and highest break-even price of almost $92 per BOE.

Wolfcamp Play

The top 5 producers in the Wolfcamp play are Cimarex (XEC), Anadarko (APC), EOG, Devon (DVN) and EP (EPE).

The average Wolfcamp well EUR for the 5 operators is approximately 228,000 BOE. The break-even oil price for that average EUR is approximately $75 per BOE. That is because of poor well performance by Devon and EP whose break-even oil prices are more than $100 per BOE.

By eliminating EP from the calculations, the average EUR for the play is approximately 303,000 BOE and the associated break-even price is about $61 per BOE.

Anadarko has the best average well performance with a break-even oil price of about $45 per BOE and EP has the poorest well performance and highest break-even price of almost $177 per BOE.

Bone Spring Play

The top 5 producers in the Bone Spring play are Cabot (COG), Devon (DVN), Cimarex (XEC), Energen (EGN) and Mewbourne.

The average Bone Spring well EUR for the 5 operators is approximately 294,000 BOE. The break-even oil price for that average EUR is approximately $49 per BOE.

Cimarex has the best average well performance with a break-even oil price of about $42 per BOE and Mewbourne has the poorest well performance and highest break-even price of almost $78 per BOE.

Commercial Play Areas

I made EUR maps for the 3 Permian basin tight oil plays using all wells with 12 months of production. I then used the average play EUR to determine commercial cutoffs for $45 and $60 per BOE oil prices using the economic assumptions.

Using the calculated EUR-cutoffs for the two oil-price cases, 26% of Permian tight oil place well break even at $45 per BOE, and 40% break even at $60 per BOE price.

Current well density was calculated by measuring the mapped area of the $60 commercial area and dividing by the number of producing wells within those polygons. The Wolfcamp has the lowest well density of 1,269 acres per well and, therefore, the most development potential. The Bone Spring also has considerable infill potential with 725 acres per well.

The Trend Area-Spraberry has additional development potential but a comparatively lower current well density of 281 acres per well because there are more than 6,000 vertical producing wells within the $60 commercial area defined by horizontal well EUR. These vertical wells have produced 203 MMBOE to date, approximately equal to the 206 MMBOE for all horizontal wells both inside and outside of the commercial area.

Operators routinely stress the large number of potential infill locations in their investor presentations and press releases based on very close well spacing of, for example, 40 acres per well. Although well density is important for determining play life, I doubt that well spacing of much less than 100 acres per well is economically attractive because of potential interference between wells that are drilled horizontally and hydraulically fractured.

Investors should understand that more wells is not better. Superior economics result from drilling thefewest number of wells necessary to optimize production.

Operators also stress the potential for additional potential reservoirs within the same play reservoir. That is undoubtedly true but those are not yet discovered and are, therefore, resources and not reserves of any category based on the SPE Petroleum Resources Management System. If they are so attractive, why haven’t they been drilled and produced already?

READ MORE ON FORBES

*I use a 15 cubic feet per barrel equivalent conversion based on the price of natural gas and crude oil. The conversion based on energy content is approximately 6:1 and is used by most producers to calculate BOE EUR. The EUR reported by producers are, therefore, higher than those shown in this study especially for plays and wells with high gas-oil ratios.

Posted in The Petroleum Truth Report on June 19, 2016

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The State of the Industry: Q2 2020 Financial Performance

It is, obviously, unsurprising that the recently released Q2 financials for the oil & gas supermajors contained distressed numbers as the first full quarter of Covid-19 impact washed over the entire industry. It is, however, surprising how the various behemoths of the energy world are choosing to respond to the new normal, and how past strategies have exposed either inherent strengths or weakness in their operational strategy.

Let’s begin with BP. With roots that stretch back to 1908 with the discovery of commercial oil in Persia, now Iran – BP arguably coined the phrase supermajor in the late 1990s, when acquisition of Amoco, Arco and Burmah Castrol married BP’s own substantial holdings in Europe and the Middle East to create a transatlantic oil and gas giant. It was a trend mirrored across the industry, with the Seven Sisters of the 1970s becoming ExxonMobil (Esso and Mobil), Chevron (Gulf Oil, Socal and Texaco) and modern day Royal Dutch Shell. Joining them were ConocoPhillips (Conoco and Phillips) and Total (Petrofina and Elf Aquitaine). As the world’s appetite for oil and gas increased at an accelerating pace, the supermajors became among the world’s largest and highest valued companies across the next two decades.

That is now poised for a major change. With fossil fuels waning in demand and renewables becoming more investable, BP is now declaring that it will no longer be a supermajor. CEO Bernard Looney made the announcement ahead of the release of the company’s Q2 financials, seeking to reinvent the firm as ‘integrated energy company’ rather than an ‘integrated oil company’. To make this change, Looney is looking to shrink BP’s oil and gas output by 40% through 2030 and invest heavily to become the world’s largest renewable energy businesses, putting climate change firmly on the agenda and getting ahead of the curve in meeting European directives for a low-carbon future. This was, perhaps, already on the cards. But the Covid-19 effect has hastened it. With a second quarter loss of US$6.7 billion, BP is choosing this time to rebrand itself for long-term transformation rather than maximise current shareholder value; indeed, it will slash dividends in half in order to invest cash for the future.

On the European side of the Atlantic, that trend is accelerating. Shell and Total are also aiming to be carbon neutral by 2050, alongside other European majors such as Eni and Equinor. That isn’t to say that oil or gas will no longer play a huge role in their operations – indeed Total and Eni in particular have made many recent and potentially lucrative finds in Egypt, South Africa and Suriname – just that oil and gas will become a smaller percentage of a diversified business. Both Shell and Total have also displayed how past strategic decisions have paid dividends in uncertain times. Both supermajors declared profits for the quarter, escaping the trend of underlying losses with net profits of US$638 million and US$126 million respectively when a deep red colour to the numbers was expected. The saving grace in a dramatic quarter was their trading activities, where the trading divisions of Shell and Total (as well as BP) took advantage of chaos in the market to deliver strong results. But even with this silver lining, Shell and Total are scaling back on dividends, as they join BP in a drive to diversify in the age of climate change, which has strong political backing in Europe where they are based.

On the other side of the pond, the mood surrounding climate change is decidedly different. ExxonMobil and Chevron aren’t exactly ignoring a low-carbon future but they aren’t exactly embracing it wholeheartedly either. Instead, both supermajors look to be focusing on maximising shareholder value by focusing on producing oil as profitably as possible. It explains why Chevron moved to acquire Noble Energy recently after failing to buy Anadarko last year, and why ExxonMobil is still gung-ho over American shale and its new found black gold assets in Guyana. The Permian remains on their focus; with economic pressure on, there are rich pickings in the shale patch that could turn American shale from a patchwork of ragtag independent drillers to big boy-dominated. In the short-term, that promises quick returns after the panic – especially with ExxonMobil and Chevron declaring net losses of US$1.08 billion and US$8.3 billion for Q2, respectively – but the underlying assumption to that is that the energy industry will recover and continue as it is for the foreseeable future, rather than the major upheaval predicted by their European counterparts.

For shareholders, and the companies themselves, the expectation is what the future will hold once the worse is over. That Q2 2020 financials dismal performance was never in doubt. What is more revealing is where the supermajors will go from here. Will BP’s attempt to end the supermajor era pay off? Or will American optimism return us back to business as usual? It’s two different visions of the future that will either way spell a sea change for the industry.

Market Outlook:

  • Crude price trading range: Brent – US$43-45/b, WTI – US$40-42/b
  • Global crude oil price benchmarks moved higher after a devastating blast in Lebanon that levelled a significant amount of Beirut’s port facilities
  • However, the market is also cautious as OPEC+ begins to wind its supply cuts down to a new level of 7.7 mmb/d with concerns that demand recovery is slower-than expected
  • OPEC’s Gulf nations – Saudi Arabia, Kuwait and the UAE – also ended voluntary cuts made in June, but are looking to force Iraq to 100% compliance in August and September as the latest data continues to show it lagging behind commitments

End of Article 

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In this time of COVID-19, we have had to relook at the way we approach workplace learning. We understand that businesses can’t afford to push the pause button on capability building, as employee safety comes in first and mistakes can be very costly. That’s why we have put together a series of Virtual Instructor Led Training or VILT to ensure that there is no disruption to your workplace learning and progression.

Find courses available for Virtual Instructor Led Training through latest video conferencing technology.

August, 07 2020
Suriname’s Mega Discovery

It was just over five years ago that ExxonMobil discovered first oil in Guyana, transforming the sleepy South American country into the world’s upstream hotspot in just half a decade. The strike rate there has been amazing – 18 discoveries out of 20 well campaigns, and more seem to coming as new discovery efforts get underway. This made Guyana the envy of its neighbours. And why not? The Guyanese economy is projected to grow at 86% y-o-y in 2020, despite the Covid-19 pandemic, as first commercial oil from the Liza field hit the market.

Just over the Guyana border, Suriname, a former Dutch colony had all the more reason to be envious. Unlike Guyana, Suriname has an established upstream industry. Managed by the state oil firm Staastsolie, the volumes are paltry: the onshore Calcutta and Tamabredjo field collectively produce at a current rate of 17,000 b/d. Guyana’s Liza field alone is 15 times larger than Suriname’s total crude output. But the Guyanese miracle always did herald some hope that some of that golden dust could blow Suriname’s way, not least because the giant offshore discoveries in the Staebroek block were just across the maritime border.

In January 2020, this bet proved right. US independent Apache announced it had made a ‘significant oil discovery’ at the Maka-Central 1 well, the first suggestion that the Cretaceous oil formation in Guyana extended southeast to Suriname. Two more discoveries were announced by Apache in quick succession, Sapakara West and, just this week, Kwaskwasi. All three are located in the 1.4 million acre offshore Block 58, which was originally held entirely by Apache before French supermajor Total bought into a 50% stake just before the Maka Central discovery was announced. Three discoveries in six month is quite a payoff, especially with the Kwaskwasi-1 well delivering the highest net pay and confirming a ‘world-class hydrocarbon resource’. More importantly, initial findings suggest that Kwaskwasi holds oil with API gravities in the 34-43 degree range, the sort of light oil that is perfect for petrochemicals and higher-grade fuels.

With Total scheduled to take over operatorship of the block after a fourth drilling campaign, the partners are eager to extend their streak. The Sam Croft drillship is scheduled to head to Keskesi, the fourth scheduled prospect in Block 58, after operations at Kwaskwasi-1 have concluded, and an additional exploration campaign is already in the plans for 2021.

Total and Apache aren’t the only ones playing in Surinamese waters, though they are the first to hit the payday. Most of the country’s offshore blocks have been apportioned, snapped up by ExxonMobil, Kosmos, Petronas, Tullow and Equinor, and all are hoping to be the next to announce a find. ExxonMobil, with Equinor and Hess Energy, have a good position in Block 59, just next to the Caieteur block in Guyana, while Kosmos is hunting in Block 42, right next to the Canje block in Guyana. However, it is Malaysia’s Petronas that is the next likely candidate. Present in Suriname since 2016, when it drilled the exploratory Roselle-1 well in Block 52, Petronas also has interests in Block 48 and Block 53, and recently completed a farm-out sale with ExxonMobil for 50% of Block 52. Its drilling campaign for the Sloanea-1 well is scheduled to begin in Q4 2020, and will be keenly watched by all in Suriname.

Unlike Guyana that had no state oil company, Suriname has existing national oil infrastructure. Staatsolie currently controls onshore and shallow water areas in the country. However, all wells drill in offshore Block A, B, C and D have turned out dry so far. That leaves Staatsolie in a situation: its own areas are not prolific as discoveries by Total, Apache, Petronas et al. For now, Staatsolie is looking to gain rights to 10-20% of any oil discovery within Suriname, but the framework for this is weak and it must navigate carefully to not antagonise the oil majors that are powering the discoveries in its waters. It will do well to avoid the confrontational attitude that is jeopardising LNG development in Papua New Guinea with ExxonMobil and Total, but Staatsolie does have a claim to Suriname’s oil riches for itself.

For now, it is exhilarating to observe the progress in this previously quiet corner of South America. It is the closest thing to frontier oil exploration in the 21st century, with each new discovery generating more and more excitement. Who would have thought there was so much oil left undiscovered? Guyana has shot into the spotlight, Suriname is starting its own ascent and… who knows… could French Guiana be next?

End of Article 

Get timely updates about latest developments in oil & gas delivered to your inbox. Join our email list and get your targeted content regularly for free. Click here to join.

In this time of COVID-19, we have had to relook at the way we approach workplace learning. We understand that businesses can’t afford to push the pause button on capability building, as employee safety comes in first and mistakes can be very costly. That’s why we have put together a series of Virtual Instructor Led Training or VILT to ensure that there is no disruption to your workplace learning and progression.

Find courses available for Virtual Instructor Led Training through latest video conferencing technology.

August, 01 2020
2019 U.S. coal production falls to its lowest level since 1978

U.S. total annual coal production

Source: U.S. Energy Information Administration, Annual Coal Report

In 2019, U.S. coal production totaled 706 million short tons (MMst), a 7% decrease from the 756 MMst mined in 2018. Last year’s production was the lowest amount of coal produced in the United States since 1978, when a coal miners’ strike halted most of the country’s coal production from December 1977 to March 1978. Weekly coal production estimates from the U.S. Energy Information Administration (EIA) show the United States is on pace for an even larger decline in 2020, falling to production levels comparable with those in the 1960s.

2019 annual coal production by state

2019 annual coal production, top 10 coal-producing states


Source: U.S. Energy Information Administration, Annual Coal Report

Wyoming produces more coal than any other state, representing 39% of U.S. coal production in 2019, at 277 MMst, which is 9% lower than its coal production in 2018. Coal production in West Virginia, the state with the second-highest coal output, fell by a relatively smaller 2% in 2019. West Virginia is a primary producer of metallurgical coal, which saw sustained demand for exports in 2019. Coal production recently stopped in two states, Kansas in 2017 and Arkansas in 2018. Arizona stopped producing coal in the fall of 2019 when the coal-fired Navajo Generating Station and adjacent Kayenta coal mine that supplied it both closed.

EIA estimates weekly coal production using coal railcar loadings. In 2020, weekly coal railcar loadings have been trending much lower than 2019 levels, and most recent year-to-date coal railcar loadings were down 27% compared with 2019.

U.S. weekly railcar loadings

Source: U.S. Energy Information Administration, Weekly Coal Production

The decline of U.S. coal production so far in 2020 reflects less demand for coal internationally and less generation from U.S. coal-fired power plants. U.S. coal exports through May 2020 are 29% lower than during the first five months of 2019. U.S. coal-fired generation fell to a 42-year low in 2019, decreasing nearly 16% from the previous year, and has fallen another 34% through May 2020.

Estimated U.S. coal production through mid-July 2020 is 27% lower than the average annual 2019 output, and EIA expects these reductions in production to persist during the remainder of the year. In the latest Short-Term Energy Outlook (STEO), EIA forecasts a 29% decline in U.S. coal production in 2020.

EIA forecasts that U.S. coal production will increase by 7% in 2021, when rising natural gas prices may cause some coal-fired electric power plants to become more economical to dispatch. Much of EIA’s projected recovery in coal production is in the western United States.

Principal contributor: Rosalyn Berry

July, 29 2020