Douglas Buckland + 6,308 February 22, 2020 Let’s see... A new pad design somehow significantly reduces drilling and completion costs per well? Possible, but a little more info on the pad design AND where the D&C costs were reduced would be instructive... “Along with setback and unitization changes, these wells will have increased contact with the hydrocarbon-bearing rock.” How so? Exactly how has this increased the effective wellbore area through the reservoir? Just stating it does not make it so... ”Pilot well in the Louisiana Austin Chalk had Flowing Casing Pressure over 8,000 with 1,200 bbld of API 49 on restricted choke.” Flowing CASING pressure? Are they flowing through the casing?... ”Eagle Ford EOR continues with unpublicised results claiming to be exceeding models.” I have an issue with ‘unpublicized results’ and their relationship with models.... ”Their use of huff 'n puff with miscible gas mechanics portends for enormous ramifications across all shale play” Doesn’t ‘portend’ mean it might, or might NOT WORK? The “specific mention” of the black oil window would not fill me with confidence... Sounds to me like yet another ‘dog & pony’ show. Quote Share this post Link to post Share on other sites
Coffeeguyzz + 454 GM February 22, 2020 (edited) Mr. Buckland Addressing your stated issues... The design of Marathon's Bingo pad may not have played such a dominant role in cost efficiencies so much as the operational improvements. That said, the now near universal status (in the Bakken) of piped water for fracturing eliminates the expense of trucking in hudreds of deliveries of aqua. The new opening of at least one North Dakota sand mine offering effective proppant has reduced per well expenses about $250,000. Although these Bingo wells did not use electric frac'ing, AFAIK, cost savings for using field gas versus diesel is said to be in the $200/250 k per well range. Production costs are reduced with the piping of produced water and oil to nearby central units which also cuts back on individual pad logistics and expense. Operationally, 4 wells can much more efficiently drilled/cased/logged/cemented when the distance separating all 4 wellheads is about 200/300 feet. Likewise, the completions are occurring at a rapid pace with pumps, guns, plugs alternating amongst the wells in a near non stop fashion. As virtually all fracturing is now plug and perf, the ability to continue pumping while an offset is being prepared is an enormous time saver. For some context, PDC claimed a total of $2.3 million per well to D&C a 4 well pad years ago in the Niobrara. These were shorter (~5,000'), shallower (~6,000') wells. Re setbacks/unitization ... For about a decade, Bakken laterals have been described as 10,000 footers, but that is incorrect due, primarily, to regulatory restrictions. The 200 foot setback from the toe to DSU line is now 50 foot. Likewise, for cemented heels, the start of the perforated stage is also 50 feet from the DSU line These new regs, coupled with the improved short bit-to-bend motors have enabled operators to access maybe 300 to 500 hundred foot longer lateral into the rock. Precise numbers can be had from the ND DMR site with a subscription, but I no longer follow these metrics that closely. Re the casing pressure for the Austin Chalk It is the tubing pressure (do not know the size), rather than casing pressure. Having closely followed the high pressure Utica wells for years (~8,000/10,000 psi), I am accustomed to the operators describing both shut in and flowing casing pressures and incorrectly used the same description. Re EOR and, particularly, 'black oil' targeting. This topic may become one of great interest to you, Mr. Buckland, as it contains a great deal of 'new' technology ... so 'new' it hasn't even been 'invented' yet. There are - supposedly - a dozen or more EOR projects underway today, with very little fanfare. However, the laboratory work has been very extensive and very promising. Work in progress, to be sure, but pressure issues as well as as miscibility characteristics seem to loom large in significance. Which brings us back to shallow black oil. Years ago (seems like a lifetime) a colorful outfit named Gasfrac was racing around with their waterless, gelled propane concoction doing fracturing. Didn't work, but some interesting results emerged, nonetheless. Specifically, 2 shallow oil wells in the Eaglebine and one in the shallow Utica DID have short term (2/3 month) success in production before going tits up. Now, this seemed to validate the concept of injecting/inducing some medium/mechanism of high energy with which the liquid hydrocarbons might economically be driven into the wellbore. As the years roll by, there is simply a staggeringly high number of wells sitting right nearby to 80/90% of the original oil in place. There is NO WAY that this oil will be left behind. Edited February 22, 2020 by Coffeeguyzz Quote Share this post Link to post Share on other sites
0R0 + 6,251 February 23, 2020 (edited) 8 hours ago, Coffeeguyzz said: As the years roll by, there is simply a staggeringly high number of wells sitting right nearby to 80/90% of the original oil in place. There is NO WAY that this oil will be left behind. That is one of my caveats to peak oil modeling of shale LTO. At just a bit higher oil price you can go and refrac the entire legacy spent well stock with better EOR methods (e.g. C1 C3 C6 critical extraction) to get up to 30% of TOC in a first huff n' puff and up to 40% or more in a second. even just CO2 injection can increase recovery to 13-14%) After a first frac having taken out 5-10%, the refrac may be just as productive with a miscible gas injection. I a thinking ( or rather starting to) of shale being more like coal than like oil as far as the resource modeling goes. Edited February 23, 2020 by 0R0 1 Quote Share this post Link to post Share on other sites
Gerry Maddoux + 3,627 GM February 23, 2020 That's what I've been harping on: You can't model something that is subject to constantly changing recovery methodology. By the time you get models built for peak demand, or peak oil, the whole thing changes. For example, if say, the primary feedstock for petrochemical plants changes from oil to LNG, then peak oil is going to be delayed by maybe ten years. If (as appears to be the case) gas-lifting in low-pressure reservoirs becomes commonplace, peak oil may never occur; it might be that demand fizzles while we still have plenty of oil. Those models are pretty, and kind of fun to talk about, but most of them are stale by the time they make it to a presentation. I don't even think a lot of the modelers have ever been out to an oil field. But it's not just the model-makers: no lesser personage than John Hess said that he thought the Bakken would be drilled out by 2025. I seriously doubt that. I think they might be cranking up a pretty good gas-lifting program by then, and a refracking program. Quote Share this post Link to post Share on other sites
ceo_energemsier + 1,818 cv March 5, 2020 Chevron ups Permian Basin resource estimate to over 21 billion boe, double 2017 estimate Company's Permian output could hold around 1.2 million boe/d Has lineup of investment targets to fund projects over next decade Green light for US Gulf Whale, Ballymore projects eyed in 2020-2021 Chevron has upped its Permian Basin resource estimate to more than 21 billion barrels of oil equivalent, more than double the company's estimate just three years ago, its top executives said Tuesday. The company's 2017 resource estimate for the basin, the largest source of oil output in the US and a significant source of natural gas, was 9 million boe, Jay Johnson, Chevron's executive vice president of exploration and production, said in webcast remarks at the company's annual Security Analyst Meeting in New York. And the major expects to take final investment decisions on two 2018 deepwater discoveries in 2021 and 2022, Johnson said. With flat prices, Chevron expects the Permian, in West Texas and New Mexico, to eventually generate more than $4 billion/year of free cash flow, he added. Chevron's output from the play is expected to top 600,000 boe/d this year and 1 million boe/d in 2024, Johnson said. "We believe our Permian production has the potential to grow and sustain at around 1.2 million boe/d," Johnson said. Moreover, the production and free cash flow Johnson cited are based on development of only half the company's 2.2 million Permian acres and only a portion of the play's multiple "benches" or sub-zones, he said. Free cash flow is a key financial goal of most upstream operators in the current low oil-price milieu. Beyond that, the company also has what Chevron CEO Mike Wirth said were future investment opportunities within its portfolio for several years and beyond. LATE 2020s DEVELOPMENTS "Many of these positions are facility constrained, meaning with backfill projects, production has little to no decline," Wirth said. "We expect successes that will result in developments during the second half of this decade." These projects range from LNG, led by the Gorgon and Wheatstone developments in Australia, shale and tight oil anchored by the Permian and including the Vaca Muerta play in Argentina and the Duvernay Shale in Canada, the Tengiz expansion project in Kazakhstan that will raise production to 1 million boe/d in 2023 and the Gulf of Mexico, Wirth said. The company has 232 blocks in the US Gulf with 62 active prospects. Beyond that, additional upside potential may come from increasing activity in the Permian and other shale plays, ramping up production in the Neutral Zone between Saudi Arabia and Kuwait and of heavy oil in Venezuela, Johnson said, adding importantly, these assets are already in Chevron's portfolio. US GULF OF MEXICO A BRIGHTER SPOT In addition, Johnson suggested the Gulf of Mexico is a brighter spot for the company than it has been in years. Chevron continues to acquire exploration acreage in the Gulf, where it is one of the premier explorers and producers, and expects to sanction two additional projects in the next two years after green-lighting Anchor last year. Whale and Ballymore, back-to-back finds in 2018, are expected to receive the go-ahead in 2020 and 2021. Whale, a remote field off the Texas Gulf Coast, will be a standard facility design, while Ballymore, further east off the toe of Louisiana, is envisioned as a possible tieback to an existing production hub. Anchor, which has involved development of new technology enabling the extremely high-pressure field to prepare for production in 2024, will also benefit other such prospects. Chevron plans to drill 11 potentially impactful exploratory wells around the world this year, including four in the US Gulf, two in the Mexican Gulf of Mexico and two in Brazil. Also, Wirth said the previous company-wide total projected capital and exploration budget of $19 billion-$22 billion/year for the next three years has been extended to a fourth year (2024). Chevron has affirmed a $20 billion capex budget for 2020. DECARBONIZATION As the oil industry has become increasingly vocal about committing to decarbonization in the last few years, Chevron executives said they are pursuing those initiatives although not as a separate business. Instead, they are integrating and weaving it into projects where appropriate. While the company has vastly reduced its exposure to US gas production per se, it is involved in LNG. Chevron aims to improve returns at two such Australian facilities, Gorgon and Wheatstone, and will look at other opportunities to expand its LNG portfolio, Wirth said. "But they have to be the right ones," he said. "We're in no hurry to do anything there [in that arena]. Everybody who's looking at making final investment decisions on LNG is going to have to be pretty thoughtful about when and how they step into that market." Quote Share this post Link to post Share on other sites
ceo_energemsier + 1,818 cv March 5, 2020 Energy CEOs: World will watch how Permian protects environment https://www.mrt.com/business/oil/article/Energy-CEOs-World-will-watch-how-Permian-15099936.php#item-85307-tbla-5 Quote Share this post Link to post Share on other sites
ceo_energemsier + 1,818 cv March 5, 2020 Chevron’s $80 Billion Pledge to Investors Exceeds $100-Crude Era Chevron Corp. plans to hand investors billions of dollars more than it did during the heyday of $100-a-barrel crude as the U.S. supermajor ramps up oil output in the Permian Basin. In a surprise move, Chief Executive Officer Mike Wirth pledged Tuesday to lavish as much as $80 billion on dividends and share buybacks over the next half decade. The projected returns exceed levels paid out in the years preceding the worst-in-a generation 2014-2016 market collapse. The key driver of those returns will be crude production from the Permian Basin of West Texas and New Mexico, which will double over the next five years and eventually account for a third of the company’s global output. The targets, unveiled by Chevron at its annual investor meeting in New York, are illustrative of the high-wire balancing act facing Big Oil. The industry’s largest companies are being asked to reinvest in future production, reward shareholders, and, at the same time, work through an energy transition that may spell the end of fossil-fuel growth within a decade. Chevron’s projected investor returns “look well supported by the balance sheet,” RBC analyst Biraj Borkhataria said in a note to clients. The presentation “looks more like evolution than revolution, and continues the prior mantra around lower for longer capex, and a steady uptick in Permian performance.” Chevron said it will save $2 billion by cost cutting and margin improvements while holding annual capital spending to no more than 10% above current levels. Returns on capital will increase to more than 10% by 2024, up a third from current levels. Returning cash to shareholders is “our number one priority,” Wirth said. “This doesn’t rely on higher oil prices. It relies on self-help to greater cost efficiency, continued capital discipline and effective portfolio management.” Chevron’s returns have languished in recent years, far below where they stood a decade earlier. Exxon Mobil Corp. has seen a similar deterioration. The Permian -- a vast, multi layered swath of oil that dominates North American crude production -- will be a key driver of Chevron’s plan to improve performance, offering more than 20% profit for each dollar invested, said Jay Johnson, chief of the company’s upstream business. Production will plateau at 1.2 million barrels a day by the mid-2020s with capital spending of about $4.5 billion a year. The Permian targets show faith in a basin in which many explorers are struggling to generate cash after taking on debts to fund expansions and drilling. Chevron is insulated from those headwinds because it inherited most of its holdings in the region during the 2001 Texaco Inc. takeover. With a strategy of emphasizing investor returns over production growth, Chevron is following the path laid down in recent years by ConocoPhillips. The strategy is a recognition that the world doesn’t need ever-increasing volumes of oil and that shareholders need to be rewarded for owning fossil-fuel producers. Cash Search Last year, Chevron returned $13 billion in dividends and buybacks, equivalent to $65 billion on a five-year basis. The new goal of $75 billion to $80 billion is equivalent to almost half Chevron’s market value. “To the general portfolio managers out there, if you’re looking for cash, Chevron is the place to be,” Chief Financial Officer Pierre Breber said during the presentation. Chevron was little changed at $96.51 at 11:54 a.m. in New York after earlier climbing as much as 2%. Quote Share this post Link to post Share on other sites
Douglas Buckland + 6,308 March 6, 2020 “This topic may become one of great interest to you, Mr. Buckland, as it contains a great deal of 'new' technology ... so 'new' it hasn't even been 'invented' yet.“ Enough said..... 1 Quote Share this post Link to post Share on other sites
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