Robert Kester

🚨 New TPA / NotebookLM Podcast Episode Alert! 🎙️ E.8 Stop Pre-Existing Corrosion from Growing: The Nuances of Batch Corrosion Inhibitor Application In our latest Trusted Pipeline Advisor episode created in collaboration with NotebookLM / AI, we take a “peanut buttery” deep dive into batch corrosion inhibition with heavy film-forming inhibitors. Imagine spreading peanut butter inside a pipeline—a thick, protective layer that shields against corrosive agents, especially in those pesky stagnant water traps. This is the magic of batch inhibitors! 🌟 What’s Inside This Episode: 🔍 Why Batch Inhibitors Are Game-Changers: Perfect for pipelines with slow-moving or stagnant water where continuous inhibitors can’t keep up. Combat the low pH environments that accelerate corrosion in water traps. Create a physical barrier, preventing corrosive water from reaching the pipeline’s surface. 🔬 The Science Behind Heavy Film-Forming Inhibitors: Continuous inhibitors: Thin molecular films disrupt corrosion at a chemical level. Batch inhibitors: Thick, adhesive coatings that physically shield pipeline walls. ⚙️ The Application Process – Turning Peanut Butter into Pipeline Protection: Mixing & Dilution: Blending heavy film inhibitors with solvents like diesel to ensure even application. Pigging: Mechanical pigs “spread” the inhibitor along pipeline walls, creating a uniform barrier. 💡 Challenges & Solutions: Preventing active ingredient separation during storage and transport. Optimizing pigging speed and inhibitor volume for effective coating. Using simple mason jar tests to ensure inhibitor readiness! 🎯 Why It Matters: For pipelines with stagnant water traps or pre-existing damage, batch inhibitors are often the only viable solution to stop active corrosion and prevent defect growth. These inhibitors are targeted, cost-effective, and essential for maintaining long-term pipeline reliability. 🎙️ Episode Highlights: 00:00 Introduction to Batch Corrosion Inhibition 00:24 Batch vs. Continuous Inhibitors 01:41 When to Use Batch Inhibitors 02:25 Application Process 03:25 Challenges & Solutions 04:08 Final Thoughts 🚀 Why Watch? Corrosion is one of the biggest threats to pipeline integrity. This episode reveals how heavy film-forming batch inhibitors tackle challenges where other methods fall short. 🎧 Subscribe to the Trusted Pipeline Advisor Podcast Channel: Stay ahead of the curve with expert insights into corrosion mitigation and pipeline integrity. Together, let’s build a safer, smarter energy future. YouTube: @trustedpipelineadvisor Spotify: TPA #pipelineintegrity #corrosionprevention #RiskManagement #qualitymanagement #TrustedPipelineAdvisor #pipelines #oilandgas #corrosionmitigation #corrosion

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This study delves into the potential of CO2 storage by leveraging CO2 fracturing technology in shale reservoirs. The study suggests that around 1000 future wells in China's Gulong shale oil reservoirs could harness similar storage potential, amounting to a storage capacity of nearly two million tons by 2030. While sounding impressive, remember that last year, all the world's nations combined pumped nearly 38.2 billion tons of carbon dioxide into the air from the burning of fossil fuels such as coal and oil, according to new international calculations on global emissions published in the journal Nature Climate Change.

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Two wells 30 ft apart drilled 10 years apart. Do not produce 5% of Darcy's Law 0 skin potential, indicated skin damage of +30+. If one studies the microlog and the neutron density crossover on the 2005 discovery 83-20, you will see that the neutron log reads higher than the density in all but the top 1 foot of the zone, where they stack. Although the wireline company indicates their microlog does not work well in smaller holes (6-1/2), this also happens to coincide with the best permeability indication on the microlog. Note that this well was probably not drilled that overbalanced (poor mud and virgin pressure) and that the nearly 20% Cypress Sand below does not show microlog perm either, and appears to have the same neutron-density behavior. The sand is only 1-2% clay according to the XRD analysis and the gamma is extremely clean, but one plug is 14% ankerite and the other is 5% ankerite.  Ankerite has a specific gravity of 3.0, pure sand is 2.65 g/cc. So, something is making the density porosity read low and the neutron high, and it appears it is the dense ankerite. Look at the core grain densities. They average 2.68 and pure sand should be 2.65. It would also seem to correlate with scattered microlog behavior. Although it doesn’t appear to effect the perm of the core- it does the hole left behind, even drilled on air, the drilling fluid in the 2015 well.

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Learn more about revitalized enthusiasm for the Barnett Shale in the Midland Basin from Andrew Stearns TGS spotlight article.

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Do any of your assets produce solids and require a #sandmanagement program? Are you sure your initial data was correct? We often find that utilizing our #DualFlow technology enables operators to get a clearer picture of the solids in a well stream. FourPhase is assisting #OilandGas operations around the globe with #productionoptimization. Please let Aksel Skåland, or myself, take a look at your data to see if we can enhance your returns.

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Where are the biggest shale wells being drilled today? Since 2023, we're forecasting >1 million barrel-equivalent ultimate production for 1,509 wells across Lower 48. The Permian dominates, but there are exciting developments in other basins too -- let's dig in! First, a little caveat: I am also filtering to wells with >750,000 barrels EUR, otherwise gas wells would dominate the list. Setting that aside, the Permian is the clear leader by this metric, with 1,449 million barrel wells drilled since 2023. The Delaware dominates, with over 90% of millionaire wells, reflecting the outlier nature of the basin. Taking out the Permian, the Uinta is the leading basin, with twenty-four 1MMBOE wells. Recently-acquired XCL Resources tops the ex-Permian chart with seventeen, and their in-basin neighbor Ovintiv comes in second with seven. (Shameless plug: reach out for a copy of our recent XCL-SM acquisition analysis to learn more about the deal). The Appalachian Utica comes in as the next-largest emerging million-boe play, with our models forecasting 10 wells since 2023 hitting that threshold. Encino, Antero, Ascent, and EOG show up on our list here. With a higher gas-fraction, these Utica-Pt. Pleasant wells standout on total recovery compared to the others on this list: they are essentially both massive oil and massive gas wells at the same time. Most of the remaining non-Permian million-boe wells are in classics like the Williston, Eagle Ford, and Anadarko, which are still turning out top-notch wells even 15+ years into their development. Impressive! #permian #uinta #utica #oilgas

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GeolOil - How to estimate SWirr irreducible water saturation from well log curves https://lnkd.in/g4wmPP83

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🎥 New TPA / NotebookLM AI Episode Alert! 🎙️ E.13 From Blind Spots to Breakthroughs: Crude Oil Pipeline Insights with QIC Assess 🔹 Crude oil and NGL shipping pipelines might seem like simple structures, but their operations are anything but static. 🔹 Internal corrosion, driven by dynamic conditions like intermittent flow, oil-water slippage, and episodic ingress of contaminants, accounts for 80% of crude oil / liquid pipeline failures. 🔹 In this Trusted Pipeline Advisor podcast episode, we take a deep dive into how QIC Assess revolutionizes corrosion management. 🚀 What You’ll Learn in This Episode: ✅ Why traditional methods fall short in addressing real-world pipeline operations. ✅ How QIC Assess uses advanced hydraulic modeling (PIPESIM, OLGA-S) to create a high-resolution map of corrosion vulnerabilities. ✅ Insights into hidden root causes: stagnant water zones, oxygen ingress, and upstream contaminants. ✅ Targeted solutions like optimized pigging strategies and MEG injection to mitigate risk. A real-world success story showcasing significant cost savings and extended pipeline lifespan. This is more than just a discussion—it's a call to action for proactive, data-driven pipeline integrity management. 💡 QIC Assess offers a paradigm shift in managing internal corrosion for crude oil pipelines. By addressing the hidden root causes behind the majority of failures, it empowers operators to move beyond reactive maintenance to a proactive, data-driven approach. Chapters: 00:00 Introduction to QIC Assess and Corrosion Management 00:53 The Origins of NeoCorr Engineering 02:05 Formation of the Internal Corrosion Technical Subcommittee 02:53 Advanced Engineering Models and Simulations 03:33 The Evolution of QIC Assess 04:33 Introduction to QIC Assess Technology 05:07 Understanding Pipeline Corrosion Dynamics 05:38 How QIC Assess Works 08:11 Mitigation Strategies and Recommendations 13:52 Case Study: QIC Assess in Action 15:20 Conclusion and Call to Action Subscribe to the TPA podcast or visit us at the [www] trustedpipelineadvisor web-site for more insights and case studies. 🎧 Subscribe to the Trusted Pipeline Advisor Podcast Channel: Stay ahead of the curve with expert insights into corrosion mitigation and pipeline integrity. Together, let’s build a safer, smarter energy future. 🔎 YouTube: @trustedpipelineadvisor 🔎 Spotify: TPA #Innovation #PipelineIntegrity #Leadership #ContinuousImprovement #ProactiveManagement #PipelineIntegrity #CorrosionManagement #OilAndGas #PipelineSafety #QICAssess #FlowModeling #HydraulicAnalysis #AdvancedAnalytics #InnovationInEnergy #ProactiveSolutions #CorrosionControl #PipelineInnovation #EnergySolutions #notebooklm #oilandgasai #slms #sms #leadership #qualitymanagement

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check out how Danomics can help you get your data ready to rock.

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FLOW published on Permian GOR's yesterday. Since this topic brings out the crazies, we detailed empirical evidence of what is changing, and what is not changing. Some surprises. We walk through formation targets, geographies, base declines, and cube development effects. We also investigate the surprises and look at good and bad case studies. This topic is important for both the oil and gas macro picture.

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Who drilled the best wells in Lower 48 last year? At this point, we have enough data across all basins to make a ranking! In 2023, the private operator Kaiser Francis crushed it, with their 19 wells in the Permian making an average of 305k barrels in their first 12 months. Other top Permian operators like Marathon, Coterra, ConocoPhillips, and Oxy also rise to the top, but surprisingly, two Uinta operators round out the top six: Ovintiv and XCL. We have been covering the incredible Uinta a lot over the past couple years, but it’s great to see the potential translate into this kind of performance. Despite being the earliest unconventional basin, the Williston saw excellent well results last year: Grayson Mill, Chord, Marathon, and XOM all landed in the top 12. Counter-narrative, operators have extended high performance there despite a mostly-drilled play core. In our age of consolidation, many of the largest operators make this list in multiple basins, including ConocoPhillips (Permian, EF), ExxonMobil (Williston, Permian), Devon (Permian, Williston), and Oxy (Permian, PRB). However, it’s still heartening to see top privates here like Kaiser Francis, XCL, Grayson Mill, and Mewbourne, even if they’re being acquired! Encino Energy rounds out the list as the only Appalachian player, thanks to excellent Utica well results. They would rank a lot higher if BOEs were included! However, even using a 20:1 equivalency would result in a list filled with Haynesville and Appalachian operators, a reminder of just how energy-prolific shale gas wells can be. Who will top the list in 2024? Coterra currently sits atop our ranking (using forecasted production to generate a 1-year cumulative), though not as many operators make our 15 wells in-basin per year cutoff. Across Lower 48, 2024 is looking even more productive than 2023 and has the potential to be the most productive year ever for unconventionals. Next year’s ranking will be interesting! #oilgas #permian #energy

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Say what?? You’re telling me that high-frequency periodic scans *don’t* effectively reduce my #methane super-emitter detection exposure? That’s exactly right, and here’s why. At first glance, it seems reasonable to use high-frequency periodic scans (e.g. monthly or bi-weekly) of production sites to reduce your exposure to 3rd-party super-emitter detection. And certainly this strategy would make us more money. But instead of jumping to self-beneficial conclusions, we dove into the data to find clarity. We analyzed our data from scanning thousands of facilities, and then re-scanning them a week later (no intervention in between). We found roughly the same total number of super-emitters on the second scan, but nearly nine out of ten of them were *new*. In other words, after just one week, the vast majority of super-emitters had ended and been replaced by new ones. So, each time you (and third parties) scan, by and large, you will simply detect a whole new batch of super-emitters. After just one week, a periodic scan is only giving you 12% reduced exposure to super-emitter detection. Moreover, not all basins, sites, and equipment are equal. Some have much lower probability of super-emitter than others. Bottom line from the data: Blindly scanning your production sites at high frequency is a poor use of your resources. What do we recommend instead? 1. Use high-quality comprehensive data at reasonable cadence (e.g. quarterly) to identify your sites and equipment with the highest risk from a statistical perspective. If you’re already our client, we have your equipment-attributed emissions data to work from. If not, we can start with “typical”. 2. Use the data, and immediate follow-ups with investigative analysis, to determine the root cause of your super-emitters and eliminate them preventatively. This is how you will beat super-emitters and reduce methane emissions across your assets. Prioritize your resources to removing the most prevalent root causes of persistent super-emitters from your assets systemically. 3. Focus on your existing SCADA and routine site visits as the cornerstone for higher-frequency monitoring. Super-emitters are large events, so your audio, visual, and olfactory (AVO) monitoring should be effective. Teach your crews about the common signs of super-emitters so they can be on the lookout. 4. If the probability of super-emitters on a given site is still too high for your comfort, then we recommend you consider investing in fixed sensors for more continuous monitoring. However, beware that these solutions may have challenges with spatial blind spots, false alarms, and requiring long emission durations to alarm. Following this strategy, our largest 20 clients have demonstrated super-emitter reduction by 43% *year-on-year*! Want more info? Check out our recorded webinar: https://lnkd.in/gXegH-Kt API - American Petroleum Institute US Environmental Protection Agency (EPA) #leakdetection #oilandgas #emisisonsreduction

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New Drug Approval Afimetoran BMS-986256, WHO 11516 cas 2171019-55-7 2-[4-[2-(7,8-dimethyl-[1,2,4]triazolo[1,5-a]pyridin-6-yl)-3-propan-2-yl-1H-indol-5-yl]piperidin-1-yl]acetamide C26H32N6O,444.583, phase 1 Afimetoran is an immunomodulator and an antagonist of toll-like receptors 7 and 8.1,2 It is also is under investigation in clinical trial NCT04269356 (Study to Assess the Way the Body Absorbs, Distributes, Breaks Down and Eliminates Radioactive BMS-986256 in Healthy Male Participants). Afimetoran

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Long laterals are more important than ever in the Permian Basin, with 25% of Midland Basin wells and 8% of Delaware Basin wells reaching three miles (or longer). How are these long wells producing compared to shorter laterals? My top plot shows the average normalized production rates over time, grouped by lateral length. The light red comprises wells less than 2 miles, the medium red is 2 milers, and black is 3 milers or longer (for exact cutoffs, see the footnotes). Each line is normalized by the production rate per foot, adjusted to a 10,000 foot lateral. In other words, this removes the obvious effect of the longer laterals having more reservoir to produce. Looking at the production curves in this way, the long laterals produce less per foot in early time, but the gap narrows up later in the wells life. This effect is more exaggerated in the Midland Basin. Functionally, this translates to lower IPs (per foot) and shallower decline for 3+ milers. Keep this in mind as you interpret early-time productivity trends! The middle chart shows cumulative degradation of 3+ milers vs. 2 milers measured at different time intervals. Wells are grouped by Novi's Rock Quality Tiers. A couple observations: - In both subbasins, higher-quality rock has less per-foot degradation than lower-quality rock. - In both subbasins, but especially in Midland, early-time degradation is more than later time. - These metrics are noisy due to small well counts, but 24-month cums show between 4% and 10% per-foot degradation for Tier 1/2 rock. Per-foot degradation this low translates into strong economics for longer laterals, reflected in the rapid growth of long laterals in the Permian (bottom chart). Here, the Midland dominates the Delaware. ExxonMobil leads the way, with 135 long laterals drilled in 2024. Note that the Midland Basin is significantly more consolidated than the Delaware, giving more contiguous acreage for extended laterals. Increased lateral length has been a major driver of improved per-well productivity and drilling efficiency numbers that have driven solid 2024 production. With 4-mile tests now coming online, extended laterals are more important than ever in the Permian.

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Tuesday Cannonball Geologic Hydrogen Fun Findings Here are some captures that address questions of The Cajun around geologic hydrogen…. From a USGS message https://lnkd.in/g3Zh-DEX Why haven’t we found geologic Hydrogen previously? “…..the process by which petroleum forms from organic-rich rocks consumes any available hydrogen. This is one of the reasons why hydrogen is rarely found with hydrocarbon gases like methane or propane.” Is a trapping mechanism possible or likely? “For decades, geoscientists have assumed that seal rocks could not effectively contain hydrogen accumulations, because hydrogen’s small size would allow it to escape through even the tightest rocks. However, studies show that the diameter of a molecule of two hydrogen atoms is about equal to that of a single helium atom and that the two gases are likely to get trapped by similar rock layers. There are known helium accumulations that have been preserved for as long as 100 million years….” From an AI Overview conveniently provided by Google. How does geologic hydrogen form in the subsurface? “…… by "serpentinization," where seawater interacts with magnesium and iron-rich rocks in the Earth's crust, releasing hydrogen gas. Unlike fossil fuels, white hydrogen is constantly replenished, with a regeneration time potentially as short as a few decades.” This last part is very curious.... Stay tuned for further Cannonballs! At FerVID, subsurface characterization is in our DNA along with delivery. Contact us for a great outcome! #greenenergy #cleanenergy #climatechange #sustainable

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When I ran my own show for a short while, my credo was always Process & Production Chemistry. The company logo was a hexagon that, to a chemist looked like a benzene ring and to an engineer looked like a steel nut... coupled with some elegant phrasing that went like this… Hexagon: The Symbol of Universal Cohesion - Unifying squares and circles; when two opposing concepts find some way, not to compromise, but to complement each other and integrate their existence into one cohesive entity. Most of my O&G career has been working with a chemical toolbox to resolve some of the industry’s trickier problems, but any opportunity to add a different perspective pretty much always brought better value to the customer. For the most part on chemical applications, it’s… right chemical, at the right concentration, in the right place, at the right frequency, monitored the right way. How hard can it be? In some cases, it can be pretty hard… take for instance scale control. We’ve all scratched our heads to try and mitigate deposition when faced with a tricky reality. - Areas downhole and in process where injected chemical is ineffective, e.g. ESP inlet or process dead legs - Uneconomic chemical solution, be that cost of chemical and/or required injection equipment upgrade - Remote, inaccessible locations where chemical delivery and monitoring can be a significant challenge This is where other solutions can come to play. So, if you have a scale issue and suspect you need to think outside of the chemical toolbox, DM me for a chat. #scalecontrol         #halite #oilandgas               #oilandgasindustry #productionenhancememt #assetresilience ClearWELL

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Petroleum drawdowns everywhere but SPR. The EIA reports are out and overall, the total inventory down 0.9 MMB to 421 MMB whereas petroleum products drew down 2.3 MMB to 812 MMB. The latter two combined 3.2 MMB to 1233 MMB, upward pressure on gasoline prices. Net exports continue. Net oil in was 1.8 MMB/D and net products out were 5.1 MMB/D. That’s an overall net export of 3.3 MMB/D, a drawdown of 23.2 MMB, more than responsible for last week’s drawdown. The U.S. remains a net exporter of petroleum products. Production was maintained at 13.6 MMB/D. There was no change in the number of rigs working. One less rig is doing miscellaneous work and one more rig chasing gas. The ratio is 482 oil/103 gas. One less rig is working the GOM, 13 total federal, and 12 in the GOM. Crude oil prices gained $3/BBL last week, except for Brent which was up $1.11/BBL. WTI finished the week at $71.54, add $3.35/BBL for LLS and $3.05/BBL. Prices are back to their November 22 level, but still in their lower window ($65-75). The crack spread is below $9.00/BBL, where it’s been since December 4. Gasoline hit a low of $3.02/GAL, down a penny from the prior week, and is creeping back up this week. Natural gas prices at Henry Hub rose 32¢ to $3.15/MMBTU while futures rose a dime to $3.28/MMBTU. The Editorial Department of Oilprice.com writes on December 20, “Oil Prices Under Pressure as Weak Demand and Economic Uncertainty Persist” “The crude oil market faces a bearish fundamental outlook in the near term. Weak demand growth, rising non-OPEC+ supply, and cautious central bank policies are likely to weigh on prices as 2025 approaches. While geopolitical risks and U.S. export activity provide some support, these factors are insufficient to offset the broader headwinds. Long-term trends, including energy transitions and structural changes in global demand, add further complexity to the market. Traders and market participants should prepare for heightened volatility as economic, geopolitical, and regulatory factors continue to influence crude oil markets. Without significant intervention, such as aggressive stimulus measures or major supply disruptions, oil markets are expected to remain under pressure well into the new year. Oilprice.com also published an open letter to Secretary of Energy nominee Chris wright from Dan Doyle , president of Reliance Well Services, on December 16. An excerpt: “There is one long-shot regulation reversal that might work, however. Undo the damage of the Inflation Reduction Act of 2022 in which the federal royalty rate was increased by 33%. What a tremendous boost, a trickle down right to the bottom line. But there’s a rub, and that is that the IRA is now law and rolling back royalty rates would require an act of Congress. You know, the place where our fellow Republicans hold a five-seat advantage. As beneficial as this one would be, it doesn’t look good." Merry Christmas. "I'll be back".

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How might we lower the cost of frac? That’s a question we have constantly asked in developing EF5 and Vortex technologies! #fracdifferent

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