Gregory Stanley

Locus Bio-Energy and Cal Coast Acidizing Co. are transforming acid remediation in California with AcidBoost. √ Lower chemical volumes √ Fewer chemicals on the job √ Higher increases in production √ Longer time between acid jobs √ Better safety profile by eliminating toxic solvents Read more in our recent article in Oilfield Technology below!

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Some helpful observations are below from a leading expert at Bridger about methane emissions monitoring. The need for methane monitoring at the equipment level, site level, basin level, and jurisdiction means that organizations have to use the right tools to answer the right questions. Are you monitoring the emissions release to be able to track and report those observations, or are you using the monitoring data to plan detailed mitigation interventions? For governments and regulators there is a need for the broader reviews to understand what the sector in general is doing. As an operator, closer monitoring solutions will help pinpoint the equipment that needs be be ungraded to reduce emissions.

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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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I like the information the Dallas Fed releases on energy, especially relating to the oil and gas industry (Q1 2024 survey linked in comments) This chart from their last quarterly survey keeps sticking in my mind.... The profitable price of development is going up and is $64/bbl on avg. This makes sense as operators are moving into Tier 2+ rock (less productive) and face inflated costs of services along with higher cost of capital. I think a lot about how our industry innovated in the late 90's through ~2010 and I wonder what might be the next innovation that pushes recoveries even further....

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Interesting idea. JSON is probably the best format to maintain balance for a couple of different prospects.  For blocky data like full-waveform sonic logging, my preferred format is HDF5, which excels at both metadata and multi-dimensional blocky data. However, HDF5 introduces a lot of issues when it comes to stational measurement data and non-uniform sampling logging curves. Additionally, HDF5 is not very cloud-friendly.

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🚨 New TPA / NotebookLM Episode Alert! 🎙️ E.7 From Diagnosis to Action: Relying on QIC Assess to Create Smarter Corrosion Management Plans Pipelines are the silent heroes of our energy infrastructure, but threats like internal corrosion can jeopardize safety and reliability. In this episode, we spotlight transformative quantitative risk assessment tools for internal corrosion hazard profiling and for the creation of hazard-optimized corrosion management plans; QIC Assess, and the Corrosion Management Plan for Internal Corrosion (CMP-IC). 🔬 Through a compelling case study of a wet-gas pipeline, we unveil the power of advanced data integration, predictive modeling, and proactive mitigation strategies to outsmart corrosion before it strikes. 🔍 What You’ll Discover: ✅ QIC Assess: Precision Diagnostics for Pipelines 🔹 Pinpointing vulnerabilities with a combination of deterministic and probabilistic models. 🔹 Transforming raw data into actionable insights for smarter, safer decisions. ✅ CMP-IC: From Diagnostics to Action 🔹 Optimized mitigation strategies, including pigging schedules and inhibitor injections. 🔹 Seamlessly updating plans as conditions evolve, ensuring a proactive approach. ✅ Case Study: Wet-Gas Pipeline Challenges Solved 🔹 Identifying water pooling hotspots in low-velocity sections. 🔹 Predicting fluid behavior and deploying VCIs with precision. 🔹 Preventing corrosion with data-driven pigging and chemical treatments. ✅ The Impact: Why Proactive Management Matters 🔹 Cutting integrity management costs by up to 60%. 🔹 Enhancing safety, reliability, and environmental stewardship. 🔹 Shifting from reactive fixes to a strategic, forward-thinking model. 🎙️ Episode Chapters: • 00:00 - Introduction: The Silent Threat of Internal Corrosion • 01:00 - NotebookLM: Smarter Decisions with AI • 02:00 - QIC Assess: Diagnosing Risks with Confidence • 03:00 - CMP-IC: Turning Insights into Action • 04:00 - Case Study: Solving Wet Gas Pipeline Challenges • 05:00 - Lessons Learned: Building a Safer Future 🚀 Why Tune In? Internal corrosion is more than a technical issue—it’s a threat to safety, the environment, and energy security. This episode dives into solutions that are transforming pipeline integrity management. Learn how to: ✔️ Predict risks with precision. ✔️ Optimize operations and reduce costs. ✔️ Safeguard critical infrastructure for future generations. 🎧 Subscribe Now: Stay ahead in pipeline integrity and safety. Follow Trusted Pipeline Advisor on YouTube and Spotify for insights into the tools and strategies reshaping the industry. 💡 Together, we can make pipelines safer, smarter, and more sustainable. #PipelineIntegrity #CorrosionPrevention #RiskManagement #QualityManagement #NotebookLM #QICAssess #DataDrivenSafety

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Chevron and Callon recently drilled U laterals in the Delaware and Midland Basins, respectively. Congrats to both teams. Word has it that Chevron “knocked it out of the ballpark” drilling a 6-1/8” hole with an RSS. RSS’s have been used in the turn on at least six wells with four successful efforts where the entire turn was drilled with an RSS. Examine the survey file from the RSS-drilled Millard K 13 well, Coterra’s first U lateral--the doglegs are unbelievably low. PDC, in the DJ, is said to have drilled two U’s with RSS’s. The survey sheet on the HEN 06NHS shows PDC drilled thousands of feet without a DLS over 1.0! A bent housing motor cannot have generated such low numbers. Chevron’s survey file from the RSS on the Hay Olivia No 0013WA well has not been posted to the RRC’s website yet, but when it is uploaded, I expect similar low DLS’s. RSS’s are successfully drilling the turn in 6-1/8”, 6-3/4”, 8-1/2” and 8-3/4” hole sizes with high DLS capability. The industry is working on an RSS that will cover the 7-7/8” hole size. The reduction in doglegs and tortuosity will be important as operators attempt more challenging U laterals. What are some advantages of RSS’s in the U? -         ROP is higher in rotation -         The doglegs are very smooth unlike with a bent housing motor -         The drilling is done entirely in rotation improving hole cleaning -         With a reamer in the hole, wiper trips and reaming down stands is not needed If you know of any other RSS usage in the turn, drop me note on the results. Likewise, if you know of any U laterals that have been drilled, let me know and I’ll add it to the U lateral list at udriller.com.

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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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My team, JP3 Measurement, LLC, sent along this case study showing the variability in heating values (BTU) of associated gas. The study shows a financial valuation swing of over $4MM/yr at a single gas gathering point. The US EIA lists about 165K wells that produce over 1MMscf/d in associated gas from oil wells. The potential associated gas valuation swing (at current prices) may exceed $66B USD annually, assuming 10 wells per gathering site. These numbers continue to grow; the most recent STEO report from the EIA, which estimates the associated gas from the Permian will increase by 1.8M Bcf/d by 2025. https://lnkd.in/gAZr9znU Flotek Industries, Inc. | JP3 Measurement, LLC | Railroad Commission of Texas | U.S. Energy Information Administration #permianbasin #eaglefordbasin #dataanalytics #associatedgas

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Finding more of it at 1/2 the price. Not every organization has the technical acumen to organically grow - but EOG demonstrates that old-school technical ability and execution is a more profitable business model for shareholders than being high-bid on everything. #OilAndGas #Geology #Engineering #TraditionalEnergy

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Bakken is out of good rock, the boom is coming to an end. I've used shap values (a package that helps explain machine learning models) for almost 7 yrs now and yet last week I found a new way to use them. One of the key questions in unconventionals right now is whether future well productivity will start declining. Shap can help us understand the likelihood. The graph shows the relative contribution to productivity over time of each category on a per foot basis while normalizing the effect of all other variables. This is the clearest look we can get at how each variable is impacting well outcomes. See the attached graph for a look at how these values are changing on average over time. Bakken had a big year last year and many seem to think it will again this year, but how long will it last? We can explore that question by looking at the trends of shap values in-basin to date. A few things stand out to me: *Completion improvements are slowing down and are almost flat now *Lateral length degradation continues as operators drill longer laterals *Operators are upspacing to maintain capital efficiency Most importantly though, for the first time since 2014, we can say the basin is in rock quality decline. We drilled fewer wells in 2020 due to low prices which allowed for high grading, but that is seemingly behind us. Since 2021 rock quality has been on a negative trend and we are now below the quality we drilled in 2019. The only future gains to be had seem to be in longer laterals despite the per foot productivity degradation. The writing appears to be on the wall. Without extending laterals quickly, and probably even beyond 4 miles somewhat soon, productivity in Bakken will be on the decline from here on out. What do you think? Will operators find ways to continue to improve productivity despite running out of top tier rock? Is there anything they can do besides drilling longer laterals?

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Great article shining new light on an old, inaccurate, and misunderstood API test. The article also introduces the new TrueCrush™️ test, which is gaining traction among E&P’s interested in accurate sand comparisons, permeability/conductivity analysis, and improved forecasting.

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A big drawdown in petroleum products this week. The EIA reports are out and overall, we drew down 8.3 MMB to 1634 MMB. SPR continues building, up 1.2 MMB to 386 MMB. Crude oil drew down 0.5 MMB to 426 MMB and petroleum products drew down 9.0 MMB to 823 MMB. The latter two drew down 9.5 MMB to 1248 MMB, putting upward pressure on gasoline prices. Exports continue as before. Net oil imported was 1.7 MMB/D and net products exported was 4.9 MMB/D. The result is a net export out of 3.2 MMB/D, a drawdown of 22.5 MMB for the week, dwarfing the overall reduction in inventory. Production continues to hold 13.5 MMB/D. The rig continues to hold at 585. Two less rigs are chasing oil, both leaving the GOM. Two more rigs are chasing natural gas  - 480 oil/101 natural gas. The federal and GOM counts reduced by two each – 18/16. Oil prices rebounded last week, up $1.92 for LLS, $2.24 for WTI and $2.87 for Brent. WTI finished at $72.02/BBL Add $3.60/BBL for Brent and $1.40/BBL for LLS, somewhat below the usual differentials. The 3-2-1 crack spread fell 2¢ to $10.97/BBL. Gasoline fell 4¢ to $3.14/GAL. Natural gas rose 11¢ on the spot market at Henry Hub to $1.93/MMBTU. Futures rose 6¢ to $2.34/MMBTU. It looks like business as usual, with all inventories in their normal operating ranges, i.e. SPR is above its new low. ZeroHedge posted an article on Oilprice.com 10/28, “The Unseen Energy Transition: How Hydrogen is Cleaning Up Our Mix”. The highlights: ·        The history of human energy use has involved a gradual shift towards fuels with higher hydrogen-to-carbon ratios, resulting in cleaner energy sources. ·        This transition stalled around 1970, primarily due to the failure of nuclear energy to expand as anticipated. ·        The transition has resumed in recent years, driven by the rise of natural gas, and the next step involves further increasing the use of hydrogen through technologies like nuclear power and advanced power plants. Alex Kimani updated the news about Israels revenge attack on Iran on 10/30 on Oilprice.com, “Iran’s Energy Infrastructure More Vulnerable To Future Attacks.” “Three days ago, the Guardian reported that Israel used precision air and drone strikes to principally target air defense systems protecting crucial oil and gas facilities, as well as military sites linked to Tehran’s nuclear programme and ballistic missile production. “Some of the targeted air defense systems include the Abadan oil refinery, the Bandar Imam Khomeini petrochemical complex, the gasfield Tange Bijar, and the Bandar port in the south of the country. Overall, Israeli media reported about 20 hits. StanChart notes that damage to air defenses on Iran’s energy infrastructure has increased their vulnerability to future attack, a development that the market appears to be overlooking, or at least underappreciating.” An interesting development. “I’ll be back.”

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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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I know and have seem how hard it is for field teams to manage AVOs. From spreadsheets to paper forms or out of date expensive software, the teams in the field need something better! No matter the size of the company, we can provide an affordable solution to get you out of a compliance nightmare and bring you a streamlined solution in a matter of weeks! Reach out, we would love to give you a demo! #LDAR #Oilandgassoftware #AVO #Compliancemanagement

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The Eagle Ford Shale, a major U.S. shale play since 2008, continues to show growth potential despite its maturity. Recent trends highlight new asset acquisitions and innovative drilling and refracturing techniques. As of March 2024, there were 55 active rigs, with a focus on oil drilling. The Eagle Ford has the fewest drilled but uncompleted (DUC) wells among major U.S. shale basins, and oil production reached 1.147 million barrels per day. Learn more in this TGS Spotlight Article by Asal Rahimi Zeynal..

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Mud on Cuttings Ratio (MOC) - the cost of waste disposed If you dig into the cause & effect of the MOC number, you will likely uncover a couple of interesting findings. First question to ask is what is the shaker screen cut point? If you are running course mesh screen on the primary shaker and a finer mesh screen on your drying shaker, this is likely contributing to your high waste volumes. Second question to ask is what is my centrifuge utilization? If you are only using the centrifuge to cut the mud density at the end of the well, chances are there is little to no solids removal being achieved. If you are not removing drilled solids, you must be diluting them, this method is not only expensive but the ultrafine particles never get removed, they just get ground smaller, to a size that eventually can't be removed by the solids control equipment, resulting in a fluid that is very abrasive to downhole tools, mud pump consumables. What happens with a "neglected" mud system as the ultrafine colloidal drilled solids starts to grow in concentration, the mud engineer will need to add additional emulsifier and wetting agent to maintain a stable emulsion. What generally happens is most of the emulsifier gets taken up with the additional drilled solids that eventually creates a physics principle called Adsorption. Its where the emulsifier and wetting agent do a very good job at encapsulating the colloidal drill solids creating a strong bond between the mud and drilled solids. Due to this high surface tension bond, the mud wants to hold everything tightly together so that when the cuttings get conveyed across the shakers, the g-force is not high enough to release the liquid from the solids. As a result, more mud is getting conveyed out as waste, more mud means more base oil, more emulsifier, more lime, salt, etc. More trucks hauling waste, more trucks hauling mud products. Completely unnecessary spending. Reach out to our friends at NPTLabs, Bob Troy get your mud system 3rd party checked by the best analytical lab in the business. Gravimetric Retort Analysis, Particle Size Distribution and XRF/XRD Analysis can tell you everything you need to know to help you save some serious dollars. Measuring Mud Matters.

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