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The U.S. Energy Information Administration’s (EIA) forecasts the United States to remain a net exporter of natural gas through 2021.

In its Short-Term Energy Outlook (STEO), EIA said net natural gas exports are forecast to average 7.3 billion cubic feet per day (Bcf/d) in 2020 and 8.9 Bcf/d in 2021, a 3.6 Bcf/d increase from 2019.

In 2017, the United States became a net natural gas exporter on an annual basis for the first time in 60 years.

Strong natural gas export growth in recent years is mainly the result of increased exports of liquefied natural gas (LNG). U.S. LNG exports averaged 5.0 Bcf/d in 2019, 2.0 Bcf/d higher than in 2018, as a result of several new facilities placing their first liquefaction units—referred to as trains—in service.

This year, several new trains are expected to begin operations: Trains 2 and 3 at Cameron LNG in Louisiana, Train 3 at Freeport LNG in Texas, and six remaining Moveable Modular Liquefaction System (MMLS) units (Trains 5–10) at Elba Island in Georgia, EIA said.

In 2021, the third train at the Corpus Christi facility in Texas is scheduled to come online, bringing the total U.S. liquefaction baseload capacity to 10.2 Bcf/d.

LNG exports are projected to continue to grow—averaging 6.5 Bcf/d in 2020 and 7.7 Bcf/d in 2021—as facilities gradually ramp up to full production.

EIA also forecasts that pipeline exports will continue to grow through 2021. Gross U.S. pipeline exports rise from 7.8 Bcf/d in 2019 to 8.1 Bcf/d in 2020 and to 8.5 Bcf/d in 2021.

U.S. pipeline exports to Mexico began increasing after expansions of cross-border pipeline capacity were completed. From January through October 2019, U.S. pipeline exports to Mexico averaged 5.1 Bcf/d, which is 0.5 Bcf/d higher than the 2018 annual average, according to EIA’s Natural Gas Monthly.

Although U.S. net natural gas pipeline imports from Canada have been steadily declining since 2016, the United States is projected to remain a net natural gas importer from Canada through the long-term because imports from Canada will remain a supply source for the United States during the winter.

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Asian refiners must import more Atlantic basin crude to fulfill demand, and the US' WTI crude is gaining market share, competing with Forties, ESPO and Murban.

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IHS: LNG industry set six new records in 2019

Records set by the LNG industry in 2019 are indicative of a sustained growth trend, with global LNG capacity expected to increase by more than 50%—from 283 MMtpa in 2015 to 437 MMtpa in 2020, according to a new report from IHS Markit.

 

 

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Records set by the liquified natural gas (LNG) industry in 2019 are indicative of a sustained growth trend, with global LNG capacity expected to increase by more than 50%—from 283 million metric tonnes per annum (MMtpa) in 2015 to 437 MMtpa in 2020, according to a new report from IHS Markit.

“The ongoing pace of new investment is especially noteworthy considering a market context of weak global prices,” said Michael Stoppard, chief strategist, global gas at IHS Markit. “Not only did LNG grow at an unprecedented rate in 2019, but the industry also laid the foundations for continued strong growth into the middle of the decade.”

2019 LNG industry records

Record levels of new investment. Final investment decisions (FIDs) for liquefaction projects were made at an extraordinary level of 70.4 MMtpa—40% higher than the previous all-time high reached in 2005 (50.4 MMtpa). The US, Russia, and Mozambique each set individual highs for levels of annual FIDs.

Record levels of FIDs without long-term contracts. Some liquefaction FIDs were made either without long-term contracts or were underpinned by sales to affiliates. Such “affiliate marketing” reached a record 43 MMtpa. Affiliate marketing at this scale has not been common in the LNG industry. Historically, most projects have instead secured long-term offtake contracts prior to committing to investment. By choosing to proceed without third-party contracts, projects can be developed more rapidly.

Record liquefaction project start-ups. New liquefaction start-ups amounted to 38.8 MMtpa of capacity, narrowly surpassing the previous high set in 2009. Recent start-ups were concentrated in the US, Australia, and Russia. The pace of project starts is expected to slow in 2020 to 28.6 MMtpa of capacity. The US will continue to dominate in this area as it mostly completes its current wave of projects.

New global supply leader. Australia surpassed Qatar as the top LNG exporter for 2019, reaching 80.2 MMt relative to 72.5 MMt in 2018. Australia is expected to extend its lead in 2020 and retain its position as top exporter until 2023 when US is projected to become the largest LNG producer.

Record European imports. Europe set records for imports each single month as well as for the year as a whole. Annual net imports totaled 87.2 MMt which exceeded the previous record of 65.5 MMt set in 2011. Imports are expected to remain strong in 2020 due to additional new liquefaction supply coming to market. New supply in 2020 is expected to outpace Asian demand growth and therefore maintain sales into Europe.

Record Chinese imports. China overtook Japan as the world largest LNG importer in the month of December 2019, with volumes for the month reaching 7.3 MMt, compared to Japan’s 6.9 MMt. Even though Japan is expected to continue to be the world’s largest LNG importer on a total annual basis through 2022, 2019 marked the second year in a row of declining imports for the country, continuing an overall downward trend since 2015. China entered its fourth year in a row of record LNG imports, increasing its LNG imports 13.4% on a year-over-year basis.

2019 LNG trade figures

LNG supply in 2019 totaled 373.0 million tons (MMt), up 11.8% from 2018 or 39.5 MMt. The largest increases in LNG exports came from the US (37.7 MMt total, up 15.2 MMt), Russia (30.2 MMt total, up 10.1 MMt), and Australia (80.2 total, up 7.7 MMt).

Net LNG imports reached 358.8 MMt in 2019, up 40.5 MMt from 2018. Regionally, LNG imports grew the most into Europe, totaling 87.2 MMt relative to 49.9 MMt in 2018. For individual countries, the UK registered the largest growth (13.3 MMt total, up 8.1 MMt), followed by France (16.3 MMt total, up 7.8 MMt), and China (62.4 MMt total, up 7.4 MMt).

 

Japan remained the largest LNG importer, receiving 77.5 MMt in 2019. However, this was a decline from 83.2 MMt in 2018, making Japan the market with the largest decrease in LNG imports in 2019. China remained the second largest importer over the entire year. South Korea remained the third largest importer in 2019, with 41.0 MMt, however it also had the second largest decline relative to 2018 (down 3.5 MMt).

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Engineered nanoparticles mitigate frac hits: Reaching more in-place hydrocarbons increases production

An innovative treatment method uses pressure and surface-modified nanoparticles to mitigate frac hits and create a favorable fluid-flow environment.

 

 

Frac hits are costing operators billions of dollars in lost production. To help alleviate this costly issue, Nissan Chemical America Corporation (NCA) has introduced a new treatment method to mitigate the effects of frac hits and increase production in initial wells, in addition to infill projects.

The patent-pending treatment method uses fluid in combination with highly surface-modified nanoparticles. The combination provides a temporary high-stress fracture environment in the initial well, to prevent neighboring fracture interactions using the fluid. The highly surface-modified nanoparticles act to reduce interfacial tension, modify wettability, and disjoin and fragment hydrocarbons to create a favorable fluid-flow environment, which enables increased and sustained production.

THE CHALLENGE

As development of unconventional reservoirs continues with tighter and tighter well spacing, some of the current production and subsequent reserves of the initial well are often compromised. In many cases, the initial well consists of large, permeable fracture networks connecting to much tighter matrix reservoir rock. By the time the infill well is drilled, the initial well in the spacing unit may have already produced several hundred thousand barrels of fluid. This depletion often creates a lower-stress environment around the induced fractures of the parent well—in other words, a pressure sink may form predominantly in the fracture network.

As an infill well is drilled and completed, the initial well will become more vulnerable to an intersection from a nearby propagating fracture, leading to severe production losses. In addition, fracture fluid and proppant communication may occur between the neighboring wells, also leading to an ineffective stimulation of the infill well. As the name—frac hit—suggests, a powerful force is unleashed that can also result in severe damage to production tubing, casing, and wellheads.

Infill wells often demonstrate production performance of 60% or less when compared to the existing initial well. Initial well interference can include undesirable increases in water production, as well as oil output decreases that frequently do not return to their previous levels. Numerous causes have been cited, including stress reversal, tendency of infill well fractures to grow toward initial well fracture networks, and improper well spacing.

It has been reported that the longer the initial well has been on production, the higher the likelihood of an induced stress change, resulting in a higher probability of infill well interference. Negative influences can be seen in the form of fines migration, proppant migration, or fluid pressure communication between the infill well frac zone to the initial well frac zone, and vice-versa.

CURRENT STRATEGIES

With intense pressure from c-suites and investors to cut costs and increase production, hydraulic fracture interference, or frac hits, is an increasing problem in today’s more mature unconventional fields. Operators must develop strategies to combat production losses caused by frac hits. Refracturing has been explored as a potential solution, however, there are limitations when it comes to the cost-effectiveness of this process.

 

 

 

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THE SOLUTION

To help mitigate frac-hits, NCA and distributor, ELS, developed a method of driving, by fluid, a patent-pending well-additive treatment and method (nanoActiv), which is mechanically powered by highly surface-modified silicon dioxide particles. Nissan Chemical has been perfecting nanoparticle technology since 1951, and is one of the first companies to produce highly surface-modified colloidal particles for industrial applications.

The company’s nanoActiv technologies are highly surface-modified colloidal silica nanoparticles, designed to penetrate deep into the reservoir and persist with long efficacy. They are used for a variety of applications, including new well completions, remediations, re-stimulations and production services.

Through Brownian motion, nanoActiv HRT (hydrocarbon recovery technology) deploys what is known as “disjoining pressure,” a phenomenon that suggests nanoparticles lift hydrocarbons from the rock surface at the three-phase contact angle. The technology surrounds hydrocarbon drops, fragmenting them into smaller droplets, enabling efficient flowback to the wellbore. Once treated, particles exhibit substantial persistence and remain within the matrix and natural fracture network after contact flow-through, facilitating ongoing improved hydrocarbon mobility.

Another component of the treatment method uses nanoActiv  EFT (enhanced flowback technology), which is a nanoparticle micellar dispersion, stabilized using a synergistic combination of distinctive highly surface-modified silica nanoparticles, a soybean extract solvent, and a blend of surfactants. It exhibits an effective primary chemical action, enhanced with the added mechanical properties of the company’s nanotechnology. EFT delivers the unique advantages of diffusion, disjoining pressure and fragmentation. It also reduces interfacial tension for improved stimulation fluid interaction within the reservoir near the created and propped fracture facies, as well as throughout the entire propped fracture network—increasing initial oil and gas production.

LABORATORY RESEARCH

In 2019, Dr. Hassan Dehghanpour (University of Alberta) demonstrated the interfacial tension (IFT) reduction and wettability modification potential of the well-additive treatment. As wettability affects the relative permeability, the wetting state can significantly impact the productivity of a well. Scientific research concluded that the treatment method altered the wettability of Montney
formation core samples from oil-wet to water-wet conditions.

 

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MITIGATING FRAC HITS

“ELS informed us that frac hits were devastating production and operator profits,” explains John Southwell, NCA’s technical director, North America. “So, we worked together to develop a method of combining our patent-pending nanoparticles with a unique pre-loading technique, to mitigate the effects of frac hits.”

Nissan’s frac hit mitigation process begins when nanoActiv is deployed into the initial well during the re-pressurization process. The well-additive treatment, in HRT or EFT, is injected as pills or intermixed with a total volume of injected fluid. While the added fluid provides the benefits of a temporary high-stress barrier near the initial well, the nanoparticles provide the benefit of significant IFT reduction, as well as wettability modification near the wellbore, to create a much more favorable fluid-flow environment. Consequently, fracture interactions are mitigated, and more hydrocarbons are produced.

Shear fractures in infill wells are problematic in the Permian basin. Initial wells are getting crushed by offset fracs, and the infill wells, themselves, aren’t producing up to expectations. The frac hit mitigation technology is a key change element in improving production results of these closely spaced horizontal shale wells. “nanoActiv represents a step-change in technology that improves profitability” states Stephen Gornick, NCA chief reservoir engineer.

On a recent job in the Permian basin, Shear Frac Group LLC measured the type and amount of fractures created per second on the infill pad with their proprietary technology, Frac BRAIN. The infill well closest to the nanoActiv preloads showed a significant increase in the cumulative fracture count, compared to the other adjacent infill wells on the pad. Shear Frac’s engineer explained that normally infill wells have lower fracture counts, due to offset depletion; however, this was not observed in this well.

Shear Frac’s real-time, cloud-based tool links to the frac data van to help operators guide hydraulic fracture inputs and improve fracture surface area creation during operations. This technology provides a new measurement of rock failure and fracture efficiency, using surface pumping data to determine the amount of shear (complex) or tensile (planar) fractures created.

Engineers from the operator believe the reason that the initial preload was so effective with NCA’s EFT technology is because the small size (12-15 nm) of the surface-modified nanoparticles in the fluid caused the preload fluid to access parts of the tight rock that normal fluid wouldn’t enter—saturating the rock near the infill well. Combine that with a pressure barrier and lowering of the surface tension of the preload fluid by the components of EFT, and you get optimal infill fracturing. Add to this the fact that EFT was preloaded into initial wells, returned to oil production less than 10 days after coming online (one recent well is exceeding previous production amounts within the first week), and the operator is proceeding to target future pads as nanoActiv preload candidates.

FIELD RESULTS

nanoActiv has consistently caused oil to flow back sooner than the operator expected—with the well actually exceeding pre-treatment production levels. The product has been pumped in various initial well pre-load jobs across the Eagle Ford shale, and Anadarko and Permian basins.

 

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Hess declares 2020 Bakken plans: $1.3B for drilling, completion

 

 

Hess Corp intends to run six drilling rigs in the Bakken shale play throughout 2020. The exploration and production company with interests in both land and offshore oil and gas development, said the drilling rig program will help Hess push net oil production in the Bakken up to roughly 200,000 barrels of oil equivalent per day.

“We continue to successfully execute our long-term strategy, with the majority of our capital budget directed to Guyana and the Bakken—two of the highest return investment opportunities in our industry that will become significant, long term cash generators for our company,” CEO John Hess said. “We are well positioned to deliver industry leading cash flow growth while also achieving significant reductions in our unit costs

 

 

which will drive margin expansion and lower our breakeven oil price to below $40 per barrel Brent by 2025.”

In the Bakken, Hess will spend up to $1.375 billion to drill 170 new wells and bring another 175 new wells online this year. Additional spending could be put towards the funding of non-operated wells.

Hess will continue to pursue its Guyana offshore assets and explore in the deepwater Gulf of Mexico. The company is currently working to develop and bring online several offshore projects that could produce significant volumes of oil by mid-2022.  

 

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SmartPad frac tech enters the Bakken

 

Cold Bore Technology Inc., a leader in fracking completion optimization technology, has integrated the company’s proprietary SmartPAD technology with one of the largest oil producers in North Dakota’s Bakken Formation. The SmartPAD platform allows for ultra high-resolution operations data to be captured, analyzed and acted on in real-time. This results in higher levels of efficiency, increased transparency and a safer onsite environment for workers, the Calgary-based company said.

Although it is currently deployed with fracking operators throughout North America, including six of the top 10 producers, these represent the first integrations of the platform in the Bakken region.

“We’ve seen interest in our SmartPAD technology grow exponentially in the last 12 months and I’m very pleased to now have our first integrations in the Bakken which is the third largest U.S. shale oil field, behind Texas' Permian.” said Brett Chell, President

 

 

 

at Cold Bore. “We do expect further producers in the region to begin integrating the technology over the coming months as field results demonstrate the significant value of having real-time access to ultra high-resolution data.”

Benefits of SmartPAD integration for producers include:

-Remote visibility of onsite operations in real-time

-Reduced downtime

-Precise identification of average service operating times

-Increased pad efficiency and reduced completion costs

-Mitigation of several major safety issues including trapped pressure, leaking valves and hot zone incidents

How it works 

Cold Bore’s patented SmartPAD uses a combination of valve positioning, pressure monitoring sensors, field data collection systems and proprietary software to fully digitize completions operations.

The monitored data sets drive an automated algorithm that tracks and records the start and completion of each activity carried out by multiple onsite service vendors - including frac, wireline, pump down and several others - down to the second. The real-time data can then be remotely accessed by those monitoring operations from anywhere in the world.

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Foremark chemicals expands manufacturing to meet shale oil needs

 

 

Foremark Performance Chemicals has completed an expansion of its triazine manufacturing operations at its La Porte, Texas plant. The capacity increase reflects strong customer demand growth from both higher shale oil and gas production in North America as well as Foremark’s strong value proposition. The expansion includes a new triazine reactor, increased storage and handling, and a doubling of truck and rail loading capacity.

“These investments showcase our ongoing commitment to innovate, drive long-term growth and meet the needs of our customers,” said Randy Owens, CEO of Foremark. “This expansion is squarely in line with our strategy and follows the recent opening of our Oil and Gas Product

 

 

Development and Application Lab.”

Foremark, headquartered in League City, TX, is a leading supplier of triazine products, which are used for scavenging impurities found in a variety of products including crude oil, natural gas and liquefied natural gas. The company’s trademarked product called PureMark, includes a broad range of high-performance amine-based scavengers such as MEA and MMA triazine formulations. PureMark triazines are highly effective hydrogen sulfide and carbon dioxide scavengers that eliminate toxic gases and maintain asset integrity. These products improve safety, protect equipment and ensure oil and gas products meet increasingly stringent specifications.

Foremark Performance Chemicals, is a technology driven company in intermediate chemicals and derivatives for oilfield, refinery and petrochemical applications.

 

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Wood Mack analysts debate: tight oil vs deepwater

 

 

Global consulting and research firm Wood Mackenzie shares its take on the question of which is more attractive to investors: tight oil or deepwater. 

“Investors remain perplexed by the US tight oil phenomenon. But the economics of tight oil actually share all the characteristics of conventional deepwater developments,” Graham Kellas, senior vice president for global fiscal research, at Wood Mackenzie said. 

Kellas and the global consulting firm’s Principal Petroleum Economist, Joshua Firestone, looked at the impact of bonus payments, royalty and tax terms on the full-cycle economics of US tight oil and deepwater. 

At first glance, it is difficult to compare these two divergent growth themes, the team said, “Yet we’ve shown that they are more similar than you think.” 

According to the researchers, both themes have transformed in the last few years. While fundamental differences exist, the expenditure and cash flow profiles of these very different plays are converging, they said.   

 

 

We’ve also used those investment metrics to evaluate both propositions. That analysis was

 

conducted on project fundamentals: revenue and costs only,” the team said. 

Kellas and Firestone have turned their attention to the impact of fiscal terms: how do we factor in the cost of acquiring land? What about royalty rates? How big is the resource owner’s share of value? And what’s the project risk? 

Kellas said: “A wide range of fiscal terms applies to both tight oil and deepwater. Tight oil investors that own land can have ‘royalty-free’ production. 

“Combined with relatively low state and federal taxes in the US, the resource owner share of project value for tight oil landowners is the lowest of any major producing country in the world. No deepwater terms can compete with this,” he also said. 

“Tight oil leases contain known resources; it’s the quality and future commerciality of these resources that carry the risk. In contrast, deepwater exploration may result in multiple large discoveries, spread over a large area—think Stabroek in Guyana. Or it may result in no commercial discoveries at all. Discovery risk has a significant impact on the price investors are willing to pay for deepwater acreage,” he added. 

Most tight oil production is subject to royalty, and the rates can be high. As royalty is based on revenue, not profit, this has a significant impact on margins and breakeven prices. Seemingly good projects can quickly turn bad if the royalty rate is too high. And the same is true for deepwater projects, where terms have stiffened following exploration success. 

According to Kellas, “Deepwater licence areas tend to be several orders of magnitude larger than tight oil and bonuses payable are much lower on a US dollar per acre basis. But the actual sums payable can also be huge—hundreds of millions of dollars – with no guarantee that commercial production will result.” 

Most US tight oil and global deepwater acreage can be acquired for small signature bonus payments—but highly prospective acreage is expensive. 

“At first glance, this comparison suggests that discovered deepwater resources are less expensive than tight oil. But this only tells part of the story,” he said.

In the period from June 2016 to June 2019, there were far fewer deepwater transactions than in the Permian. And the popularity of the Permian at that time meant investors were keen to acquire acreage in one of the world’s few oil hotspots. 

Kellas added: “There is no such thing as a typical tight oil or deepwater asset. Instead, there is a wide spectrum of assets generating a huge range of values. Tight oil can be more valuable than deepwater, and vice versa. It all depends on the specific assumptions associated with the opportunities on offer. 

“In short, it comes down to what matters most to the investor.”

 

 

https://www.woodmac.com/news/feature/tight-oil-vs-deepwater-which-is-more-valuable/

 

 

 

 

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The North America oil boom has no end in sight. Since 2008, the shale revolution has increased U.S. crude production by 160 percent to ~13 million b/d. Canada’s output has risen 70 percent to ~5.3 million b/d. Respectively, the U.S. and Canada are the 1st and 4th ranked oil producers and both hold plenty of room to grow.

Through the 2020s, IEA has the U.S. accounting for 85 percent of new global crude supply. By 2040, even OPEC, a bloc that has long underestimated North American shale, has U.S. crude output going above 17 million b/d. Operations and technologies continue to improve and shale breakeven prices have fallen into the mid-$40s per barrel or even lower. To be sure, however, the industry would greatly benefit from a $65 WTI price or above. For the naysayers, we know that the oil is there. Even with such low prices, proven U.S. reserves have more than doubled to ~65 billion barrels over the past decade. Resource wise, USGS reports that the country could have over a trillion barrels to produce.

Yet, Canada might have even more oil production potential. According to BP, the country has 175 billion barrels of proven reserves in Alberta’s tar sands. Higher prices, more infrastructure, and greater support for exports though will remain key obstacles. In particular, with the Trans Mountain, Keystone XL, and Line 3 pipelines, an export complex to reach fast growing Asia is essential to industry expansion. Incremental domestic oil needs are just too low. Importantly though, Canada’s exports to the U.S. have still blossomed amid the U.S. shale revolution. The U.S. refinery system is configured to process heavier crude like that from Canada, so sales to the U.S. have jumped 80 percent to ~4.5 million b/d. Longer-term, EIA has Canada accounting for some 25 percent of the world’s new supply, with its output rising 85 percent to almost 10 million b/d over the next three decades.

The U.S. and Canada are highly attractive countries for business. These are open markets where the best are allowed to thrive. There is no favoritism like there is in many of the world’s key oil production zones, controlled by national champions with almost limitless government backing. Although not without issues, the U.S. and Canada are democratic societies that have predictable laws and regulatory regimes to make the international oil industry’s life much easier.

Once-mighty Mexico has become the forgotten potential new oil supplier in North America. Since 2005, industry and regulatory stagnation has sliced the country’s production in half to ~1.8 million b/d. The 2013 Energy Reforms that were aimed at bringing in new outside investment, expertise, and competition for embattled national oil company Pemex are now being pulled back by the AMLO administration. For example, all new E&P auctions have been suspended, and contracts signed since the reforms are under review. This is bad news because Pemex is over $105 billion in debt and certainly requires outside help for an oil production rebound. The country does have very high deepwater (~60 billion barrels) and shale potential (~50 billion barrels). AMLO gets only one term and will leave office in 2024, about the time when an upward oil production trend should be regained.

In any event, North American oil supply will drive new non-OPEC production for probably decades to come. It will be needed. Having no significant substitute, the reality is that global oil demand continues to parallel economic growth. SUVs, petrochemicals, and aviation fuel will compensate for any absolute reduction in global oil use that could come from overly expensive electric cars. Indeed, it will be expanding exports for the U.S. and Canada that mandate new oil output. For example, the U.S. exported over 3 million b/d of crude in 2019 and could become the largest seller by 2024.

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BP more than doubles U.S. shale oil output in 2019

 

 

 

LONDON, Feb 4 (Reuters) - BP’s U.S. shale oil production more than doubled in 2019 from a year earlier as it ramped up output following the $10.5 billion acquisition of BHP’s assets in late 2018.

Oil production at BP’s shale division, known as BPX Energy, rose to 124,000 barrels per day (bpd) in 2019 from 55,000 bpd a year earlier.

Natural gas production rose to 2,175 million standard cubic feet per day from 1,705 million standard cubic feet per day.

 
 

Capital expenditure in BPX rose to $1.94 billion in 2019, or around 12% of BP’s total capex, from $1.15 billion in the prior year.

BP has largely completed the sale some portfolios of shale assets producing mostly natural gas, which it put on sale following the BHP deal, Chief Financial Officer Brian Gilvary said.

BPX operated an average of 13 rigs in three basins in 2019, including 4 in the Haynesville basin, 6 in the Eagle Ford and 3 in the Permian.

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Shell boosts crude output in top U.S. shale field to 250,000 bpd

 

(Reuters) - Royal Dutch Shell, which plans billions of dollars in spending on shale drilling projects, boosted output in the top U.S. shale field to 250,000 barrels per day in December, the company’s Permian Basin head said on Wednesday.

 

Shell plans to spend about $3 billion per year for the next five years on shale projects, said Amir Gerges, vice president of Permian assets for Shell, at the Argus Americas Crude Summit in Houston. Its Permian Basin production rose more than 100,000 barrels per day in the last year.

“We continue to ramp up our production from our core acreage,” Gerges said.

Shell and rival oil majors Exxon Mobil, Chevron and BP are spending billions in the Permian Basin of Texas and New Mexico. The companies see shale as a short-cycle asset that complements projects such as deepwater wells that take years to bring into production.

The Permian has 30 years of so-called “tier one” high quality drilling inventory and will remain at the heart of U.S. oil growth, Gerges said. But the industry faces challenges in the region, ranging from too much natural gas flaring to inadequate infrastructure and “even today’s investor sentiments,” he said.

 

Previously, Shell indicated it might seek a way to expand its presence in the Permian, but during last week’s earnings call, Chief Executive Officer Ben van Beurden indicated the timing is not right for an acquisition.

“I think anything inorganic would not be the right thing to do,” van Beurden said.

Oil and gas companies of all sizes have been under pressure to produce more free cash and return it to investors through share buybacks and dividends.

The industry also faces pressures to reduce emissions, especially from prolific gas flaring, deliberately burning gas produced as a byproduct to oil. The practice can worsen climate change by releasing carbon dioxide.

The U.S. drilling industry flared or vented more natural gas in 2019 for the third year in a row, as soaring production in Texas, New Mexico, and North Dakota have overwhelmed regulatory efforts to curb the practice, according to state data and independent research estimates.

 

“The flaring and emissions in the Permian Basin have become famous and it’s not something we would like to be recognized for,” Gerges said

 

The region needs more infrastructure such as natural gas pipelines, but it is more important to have “robust, fit-for-purpose policies and regulatory requirements that incentivize reduction in flaring,” Gerges said.

 

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That is one of the reasons I am here. To gauge how real that capital productivity is. This chart tracks industrial production indices for oil and gas drilling and production and the ratio of production to drilling activity. Of course there are time lags and those are very considerable, so high numbers in the ratio don't really reflect what it going on in reality in a timely manner, swinging between understating productivity of drilling etc. when activity is high to overstating it when activity is low.

But the big takeaway from the chart is that today's drill productivity appears to be generally higher since 2016 than at any time before, About 50% better than the late 1980s-1990s and even a bit better than 1972. Which would suggest that real oil and gas prices have the potential to drop to 1970 levels Obviously this has been the case for Nat Gas. @ceo_energemsier Is it an appropriate expectation for Oil? That would be below $40. So the question is if it is sustainable for a number of years. .


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"We continue to successfully execute our long-term strategy, with the majority of our capital budget directed to Guyana and the Bakken—two of the highest return investment opportunities in our industry that will become significant, long term cash generators for our company,” CEO John Hess said. “We are well positioned to deliver industry leading cash flow growth while also achieving significant reductions in our unit costs which will drive margin expansion and lower our breakeven oil price to below $40 per barrel Brent by 2025.”In the Bakken, Hess will spend up to $1.375 billion to drill 170 new wells and bring another 175 new wells online this year. Additional spending could be put towards the funding of non-operated wells."

1)If the trend continues looks like brent and WTI will be the same price by 2025. 

2) 5 DUC draw down by their own plans 

3) Bakken and Permian are the best plays short term and  as profitable as deepwater. Meaning everything right now is ABOVE 40$ brent.

4) Permian (from the shell or bp post few after this copied section) has 30yr of drilling left! 

I'm pretty blown away ... good info thanks for posting!

I will assume currently most oil is 60$ brent break even still and that debt repayment and shareholder returns are above that. 

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That Cunningham character just posted another "peak shale oil" article today, 2/6.

He always strikes me as "Art Berman without the charts and graphs".

 

With all the ongoing, non stop innovation and efficiencies  (mile a day lateral drilling now the norm in Appalachian Basin with a couple of ~10,000 foot in 24 hour wells being done) increasing attention is being put on emerging artificial lift technologies.

Expect the now-normal gas lift in the Bakken to spread to other basins.

Along with improvements in the valves, intriguing concepts of "tubing within tubing" extending out to the toe have piqued the interest of several operators.

 

All that hand wringing over scrapping of frac fleets?

US Well Services, Evolution Well Services, and Baker Hughes are expanding their capacity - and order books - with these field gas supplied (or, increasingly, LNG stored onsite) turbines so as to reduce costs ~$250,000/ well.

And the beat goes on.

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Loop expects rising export volumes ahead

 

 

A flood of new crude supply headed to the eastern Louisiana coast will require more exports to soak up the supply, the head of the Louisiana Offshore Oil Port (Loop) said today.

"There's going to be a tsunami of crude coming into the area," as more supply from the Permian basin creates the need for more exports, Loop chief executive Terry Coleman told the Argus Crude Summit in Houston, Texas, today.

Loop, currently the only US facility capable of fully loading very large crude carriers (VLCCs) with a capacity of 2mn bl, can export about 1mn b/d using existing infrastructure, Coleman said.

Last June Loop loaded six VLCCs in a row because of favorable arbitrage and other unique circumstances, but volumes will be lower, at 1-4 VLCCs a month "until additional supply comes into the region," Coleman said.

The region's current oversupply available for export is about 200,000 b/d, Coleman said. The balance could shift more toward exports once the 1.2mn b/d Capline crude pipeline is reversed to move crude south toward the US Gulf coast.

Work to purge the Capline was completed late last year, and Marathon Petroleum and co-owners BP and Plains All American Pipeline plan to offer light crude shipping from Patoka, Illinois, to St James, Louisiana, in mid-2021. Heavy crude service will begin in 2022. Loop expects the reversed Capline to move 300,000 b/d in mid-2021, Coleman said.

Several companies — including Enterprise Products Partners, Enbridge, Phillips 66, Trafigura, Tallgrass Energy and Sentinel Midstream — are weighing offshore oil ports in the US Gulf coast as demand grows for exporting US crude.

Plains has looked at offshore VLCC ports, but "you probably only need one or two today, especially when you take into account the capability that the Loop has," Plains executive vice president Chris Chandler told the Argus event.

Offshore oil ports are expensive to build, and "if you are not careful in how much you spend to build the facility you can rapidly consume the advantage that you gain in loading a larger ship instead of a lightering operation offshore," Chandler said.

 

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21 hours ago, Coffeeguyzz said:

And the beat goes on.

Coffee, unless you intend to find a new hobby, like golf, I would start paying more attention to well economics, the dismal financial condition of the shale sector and how it is going to capitalize itself in the future. It won't be from free cash flow and it won't be from more debt or dilution of equity. Nobody in their right mind will buy stocks in E&P companies; those days or long gone. So all this "technology" dung heap is mute if there is no money to implement it...or nothing left to use it on. 

https://www.oilystuffblog.com/single-post/2020/02/05/Cartoon-Of-the-Week

08.07.2017_natural_gas_cartoon.png

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Mr. Roughneck

 

As has frequently been the case, you and I are in agreemant in many areas of this 'Shale Revolution', albeit coming from different perspectives.

The fact that Toby Rice is determined to get EQT viable at $2 HH is an extraordinary goal ... one which I believe he will achieve.

Certainly, a great many other upstream boys will not fare so well.

At the end of the day, SOMEBODY will be operating these assets, producing these hydrocarbons to an awaiting market.

Who that will be/under what conditions remains to be seen.

 

(Chessy's NEPA assets are simply world class. Will be interesting to see how their upcoming turmoil is resolved).

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More horseshit about the leading edge, ‘new’ technology that is going to save the shale oil industry. At the end of the day all the fracing techniques and miracle proppants simple increase the effective wellbore area without changing the underlying rock and fluid properties. At some point you reach a physical and financial limit for effective results from fracing. Eventually fluid dynamics re-asserts itself and your production declines rapidly.

I also saw a comment relating how drilling efficiency has improved since around the 80’s...no shit! Directional drilling, topdrive rigs and hydraulic fracturing were in their infancy then! The improvements in drilling operations had nothing to do with the ‘shale miracle’!

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On 1/6/2020 at 7:49 PM, ceo_energemsier said:

Drilling mud
The MSEEL provided confirmation that synthetic drilling mud produces cuttings that are more environmentally friendly to dispose of than traditional cuttings and improved drilling performance. This type of mud is commonly used by NNE and other operators in the basin.

Errr okay this MSEEL are real trailblazers, just this statement alone indicates the whole post if full of junk and in serious need of an Apple Grapple to fish it out. Lets confuse the hell out of dumbasses who don't really know too much about drilling and hopefully some of these technical turds we are throwing will stick.....

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18 hours ago, Douglas Buckland said:

More horseshit about the leading edge, ‘new’ technology that is going to save the shale oil industry. At the end of the day all the fracing techniques and miracle proppants simple increase the effective wellbore area without changing the underlying rock and fluid properties. At some point you reach a physical and financial limit for effective results from fracing. Eventually fluid dynamics re-asserts itself and your production declines rapidly.

I also saw a comment relating how drilling efficiency has improved since around the 80’s...no shit! Directional drilling, topdrive rigs and hydraulic fracturing were in their infancy then! The improvements in drilling operations had nothing to do with the ‘shale miracle’!

Looks like "oil & gas fever" reaching a climax? I am betting that renewables will win. Trump would have to bomb the Iraqi + Saudi oil fields + Qatar NG fields + wipe out all Russian production in order to find a market for that much of the stuff? Although he doing his best (Iran + Russia + Venezuela sanctions), see WTI hitting $30 before long. I have finally switched to gold.

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4 hours ago, Wombat said:

Looks like "oil & gas fever" reaching a climax? I am betting that renewables will win. Trump would have to bomb the Iraqi + Saudi oil fields + Qatar NG fields + wipe out all Russian production in order to find a market for that much of the stuff? Although he doing his best (Iran + Russia + Venezuela sanctions), see WTI hitting $30 before long. I have finally switched to gold.

Better you switch to gold as you do not seem to know much about oil. Good lick!

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Check out this absurd use of an oil reserve:

https://www.sciencemag.org/news/2020/02/company-harvest-green-hydrogen-underground-oil-fires

Oh yes, we're being environmentally friendly... by wasting half the energy content of oil underground. Hopefully the heat from the C02 formation and the consequent generation of more hydrogen will recover the wasted heat. Id wager that the efficiency is laughable, however. 

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