Blogs

Niobrara (CO & WY) - update through January 2019

These interactive presentations contain the latest oil & gas production data, from all 10,287 horizontal wells that started production in Colorado and Wyoming since 2009/2010, through January. Originally I planned to do a post on the latest data for North Dakota (through February). Unfortunately, not all data that we rely on has been published yet, which is why I decided to do a post on Colorado & Wyoming instead. The update on North Dakota should follow early next week. Visit ShaleProfile blog to explore the full interactive dashboards Oil production in these 2 states started the year at record production (after revisions), at over 620 thousand bo/d. Both states contributed to growth in the past 12 months; Colorado with ~20%, and Wyoming even at almost 50% (although from a lower base). Production in the Powder River Basin has been mostly responsible for the latter, and is now over 120 thousand bo/d. As is shown in the bottom plot on the ‘Well quality’ tab, well productivity made a big jump in 2017, but has not further increased in 2018, based on preliminary data. The big news in the past week was that Chevron bought Anadarko for 32 billion dollar, which is the biggest producer in this area (see “Top operators”). With ~100 thousand bo/d production here, this area represents about 40% of its total oil production from horizontal wells in the US, with almost all of it coming out of Weld County (CO). The following dashboard, from our analytics service (Professional), shows the location and performance of the ~1,300 horizontal wells that Anadarko currently operates in Weld County, which came online between 2013 and 2017 (click the image to see the high-resolution version). In the top-right corner you will find the performance of these wells, by year, in the familiar flow-rate versus cumulative production plot. The 2014 vintage may end up with the best average recovery, as its newer wells appear to decline more rapidly. This area is very gassy, as you can see on the map, and in the gas oil ratio plot on the bottom-right.   The ‘Advanced Insights’ presentation is displayed below: In this “Ultimate Recovery” graph, the average cumulative production is plotted against the production rate. Wells are grouped by the quarter in which production started. Also here you can see that well performance appears to have peaked (at least temporarily) in early 2017, with newer wells on a slightly lower ultimate recovery trajectory. I performed a comparison of well productivity in the DJ Basin versus the Powder River Basin. The result is presented here in the following screenshot (again from our analytics service), where I’ve selected all the wells in these 2 areas, that began production between 2015 and 2017. In both basins did well productivity increase over these 3 years, but the wells in the Powder River Basin are clearly on a path to a larger oil recovery. More gas is recovered in the DJ Basin. We were again happy to find the WSJ using our subscription service to get insights into tight oil & gas production trends: Frackers, Chasing Fast Oil Output, Are on a Treadmill. As mentioned, we should have a new post on North Dakota early next week. Production data is subject to revisions. For this presentation, I used data gathered from the following sources: Colorado Oil & Gas Conservation Commission Wyoming Oil & Gas Conservation Commission FracFocus.org   Visit our blog to read the full post and use the interactive dashboards to gain more insight http://bit.ly/2G9Hf9S   Follow us on Social Media: Twitter: @ShaleProfile
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Oil Industry and the Environment: Ways to Make It Greener

More and more companies in the oil industry are now going eco-friendly. Preserving the planet is everyone’s responsibility and oil companies are no exception. In fact, with the governments all around the world raising the bars for lower emissions and the use of renewable sources, keeping up the pace with the global sustainability trend is a must. Luckily, there are quite a few ways oil companies can make their operations greener and less harmful. Here are seven of these that are really worth taking a look at. Reducing freshwater use Water is the element the oil industry simply can’t operate without. It’s used to cool the drills and remove dirt or rock debris. Hundreds of millions of barrels of freshwater end up being used on a daily basis and in order to preserve the environment that number needs to be reduced. Even though up to 95% of the water used in the oil industry is recycled, it’s still very important to rethink the extraction process and reduce freshwater use even more. Relying on solar energy There’s no need to say that oil companies rely on energy to keep their operations running. However, when going green, it’s extremely important to reduce energy use to a minimum. That’s why we see homeowners and small businesses installing solar panels on their roofs. When it comes to the oil industry, companies such as BP are creating investment funds that are to be used on producing clean energy for their operations. Therefore, we can expect to see oil companies connecting with solar producers and relying on solar energy more than ever before. Creating 3D images 3D technology has changed many industries and oil companies can rely on it to make their operations more efficient. The way this works is that they can create 3D images of the oil wells they’re drilling and use those images to make more accurate decisions. Moreover, they can utilize 3D images to eliminate any operational inefficiencies and come up with backup plans for their operations. By doing this, they can still produce the same amounts of oil but using less energy and resources along the way. Reducing gas and fluid leaks The process of drilling can result in gas and fluid leaks and developing methods for managing them is critical. Luckily, the development of new drilling techniques has resulted in both improved waste management and reduction of potential leaks while drilling. More and more oil companies now implement closed-loop systems that allow them to stay in control of their impact on the environment. Besides this, the use of quality oilfield equipment can help both onshore and offshore operators reduce the risk of gas and fluid leaks. Using advanced drilling techniques Not so long ago, oil companies had to drill at big depths in order to collect oil. But now, engineers have come up with techniques that allow these companies to drill smaller holes and still get the same results. Not only this but innovative drilling techniques also help them reduce noise and produce less waste when drilling. The way these new techniques works is that oil wells are being extended horizontally, resulting in less disturbance to the surface. Collecting more data According to some reports, companies in the oil industry only run at 77% of their true potential. This means that if more data is collected and changes are made in their approach, they could essentially reduce their energy use even more. On top of this, they could also end up reducing the amount of waste they produce. By making most of the data they collect, oil companies could also prevent accidents that occur at their rigs and create a safer working environment for their employees. Going paperless Just like with most other industries, a large amount of documentation in the oil industry is printed every day. With the Cloud technology allowing companies to store documents on the web, the amounts of paper oil companies need could easily decrease. By moving from paper to electronic systems, these companies can help save trees and eliminate human errors. Not to mention that they could save time it takes to file papers and help their employees get more work done. The use of smartphones and tablets can help eliminate the need for paper even more. The trend of going green is increasing and we can finally say we’re moving towards a more eco-friendly future. With the implementation of the right techniques and technologies, companies in the oil industry can play their part and help preserve the planet.

US - update through December 2018

These interactive presentations contain the latest oil & gas production data from 101,165 horizontal wells in 11 US states, through December 2018. Visit ShaleProfile blog to explore the full interactive dashboards Cumulative oil and gas production from these wells reached 10.4 Gbo and 112 Tcf. West Virginia is deselected in most dashboards, as it has a greater reporting lag. Oklahoma is for now only available in our subscription services. Utah, where the Uinta Basin is located, is for the first time included in this update. December production from these ~100 thousand horizontal wells was above 6.5 million bo/d, a y-o-y growth of 1.3 million bo/d (after revisions). This was a similar growth rate as a year earlier. Natural gas production increased to ~60 Bcf/d, growing by about 10 Bcf/d during the year, which also matched the growth in the previous year. The production profiles for these wells can be seen in the ‘Well quality’ tab, where the oil basins are preselected. The average peak production rate grew by 12% in 2018 (635 bo/d vs 565 bo/d). If you group the wells by the quarter in which they began production (using the “Show wells by” selection), you will find that this increase in peak production rate continued throughout 2018. The final tab lists the top operators in these basins. EOG was far in the lead in December, followed by ConocoPhillips, Pioneer Natural Resources and Concho, which are basically sharing the 2nd spot. The ‘Advanced Insights’ presentation is displayed below: This “Ultimate recovery” overview shows the relationship between production rates and cumulative production over time. The oil basins are preselected and the wells are grouped by the year in which production started. The ~1,400 horizontal wells that started producing in the first quarter of 2012, peaked at a rate close to 300 bo/d, have now declined to 20 bo/d, and recovered 150 thousand barrels of oil in the process. The ~1,400 wells that began production 4 years later (Q1 2016), peaked at a rate roughly 50% higher, and are also on track to recover about 50% more oil, before they have fallen to 20 bo/d. A major question now is whether this relationship between initial production, and ultimate recovery will hold up with ever more “child” wells being drilled. Unlike their “parent” wells, they do have nearby producing wells. We will explore this question in more detail in the coming months. If you have questions that cannot be answered by the interactive presentations here, schedule a free demo with us here, or request a 10-day trial. Early next week we will have a new post on North Dakota, which will release February production data by the end of this week.   Production data is subject to revisions. For these presentations, I used data gathered from the sources listed below. FracFocus.org Colorado Oil & Gas Conservation Commission Louisiana Department of Natural Resources. Similar as in Texas, lease/unit production is allocated over wells in order to estimate their individual production histories. Montana Board of Oil and Gas New Mexico Oil Conservation Commission North Dakota Department of Natural Resources Ohio Department of Natural Resources Pennsylvania Department of Environmental Protection Texas Railroad Commission. Individual well production is estimated through the allocation of lease production data over the wells in a lease, and from pending lease production data. Utah Division of Oil, Gas and Mining Automated Geographic Reference Center of Utah. West Virginia Department of Environmental Protection West Virginia Geological & Economical Survey Wyoming Oil & Gas Conservation Commission   Visit our blog to read the full post and use the interactive dashboards to gain more insight http://bit.ly/2G9Hf9S   Follow us on Social Media: Twitter: @ShaleProfile
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Achieving High IRR's Financing Oil Deals

TODAY'S INVESTMENT GOAL:   How to achieve high Internal Rates of Return, (IRR), with a properly structured transaction based on existing oil and gas production … without the market risk of most oil and gas investments.  Can this be done?   Requirements to achieve the strategy and returns for discussion: Buy production at a reasonable discount Evaluate the production as to the operator’s capability to deliver what is purchased Hedge the acquired oil/gas to eliminate market risk   Requirement #1   Acquire production at a discount   The niche is the small to medium sized producer that has found development capital difficult to raise due to banking reserve requirements after the oil/gas price crash of 2014-2018.  Deal with producers that have existing PDP production that can be leveraged and provide the capital to improve it.   The oil is ‘rented’ for a term under a delivery schedule obviating the risks of onerous working interest structures, joint venture follies, drilling and equipment issues and any assortment of the usual risks.  The investor is not an oil company…   Oil Company Benefits:  Not an interest bearing loan, a footnote to the balance sheet Non-recourse Zero equity take-out, the company parts with none to the investor   Requirement #2                          Evaluate the operator’s capability to deliver The existing production is evaluated by a major engineering firm.  They deliver a comprehensive report regarding the ability of the oil company to meet their delivery obligations for the length of the term. The amount of oil purchased varies based on the capital needs of the company.  Oil/Gas is delivered on a stated monthly schedule, that matches the decline curve of the production.  The investor becomes part of the division order to secure repatriation of the invested amount, satisfying the delivery contract. Requirement #3 Hedge the acquisition to avoid market risk The desire is to avoid all market risk… a put is purchased on every barrel of oil bought, matching exactly with the delivery schedule.    What are the risks?       1. Market: Risk Factor – NONE Eliminated due to hedging      2. Counter party on the hedge: Risk Factor – MINIMAL  Reduced by using top credit firms.      3.  Delivery: Risk Factor – MINIMAL Reduced by quality engineering during due diligence.     4.  Environmental and Title: Risk Factor – NONE One of the top oil and gas law practices in the country prepares the review of title and environmental risks.     5.  Character: Risk Factor – MINIMAL Extensive background and credit record of the operator and producer is performed and evaluated.  In Conclusion: Investor Benefits:   The capability to have a high IRR, (much higher than most oil companies make historically). The investor has no downside market risk and can structure the transaction so they have upside profit potential. The investor has no operating expense, is not subject to being over-operated, has no equipment, will never get a cash call. The returns available via this structure are generous as to IRR’s, much higher than other investments with similar risk profiles.  

Eagle Ford - update through December 2018

This interactive presentation contains the latest oil & gas production data from all 22,067 horizontal wells in the Eagle Ford region, that started producing since 2008, through December. Visit ShaleProfile blog to explore the full interactive dashboards December oil production, close to 1.3 million bo/d, barely changed y-o-y. Just over 1,800 new horizontal wells were able to counter the ~45% decline in legacy production in 2018. Gas production hovered last year just below 6 Bcf/d. Initial well performance in the 2 main formations (Eagle Ford & Austin Chalk) was basically unchanged in 2018, as the bottom graph in ‘Well quality’ tab reveals. The over 3,500 horizontal wells that started since 2017 are on a path to recover 150 thousand barrels of oil in the first 2 years on production, on average, in addition to about 0.7 Bcf of natural gas. The leading operator in this basin, EOG, has been increasing output throughout 2018, and exited the year at twice the rate than the number 2, ConocoPhillips (see “Top operators”).   The ‘Advanced Insights’ presentation is displayed below: In this “Ultimate Recovery” overview, the relationship between production rates and cumulative production is revealed. Wells are grouped by the quarter in which production started. You can see here that the bulk of the wells that began production since 2011 are going to recover on average between 150 and 200 thousand barrels of oil, before hitting a production rate of 10 bo/d. This does however also include a significant number of gas wells. Filtering on well type (oil/gas) is a subscriber-only feature. The 4th tab ranks operators by the average cumulative oil production in the first 2 years. Of the larger operators (>100 operated horizontal wells), Devon, ConocoPhillips and Encana are showing the best results according to this metric. If you missed our briefing on all the major tight oil basins on enelyst last Tuesday, you can still read the full update by entering our channel here: ShaleProfile channel on enelyst. Registering is free: enelyst registration page. Early next week we will have a post on all the 11 states that we publicly cover in the US (Oklahoma is currently for subscribers only).   Production data is subject to revisions, especially for the last few months. For this presentation, I used data gathered from the following sources: Texas RRC. Production data is provided on lease level. Individual well production data is estimated from a range of data sources, including regular well tests, and pending lease reports. FracFocus.org   Visit our blog to read the full post and use the interactive dashboards to gain more insight http://bit.ly/2HZjpQa   Follow us on Social Media: Twitter: @ShaleProfile
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Permian – update through December 2018

These interactive presentations contain the latest oil & gas production data from all 19,523 horizontal wells in the Permian (Texas & New Mexico) that started producing since 2008/2009, through December. Visit ShaleProfile blog to explore the full interactive dashboards December oil production came in at around 3.1 million bo/d (after revisions), 1 million bo/d higher than a year earlier. Close to 4,400 horizontal wells were completed in 2018, 23% more than in 2017. As is represented by the blue area in December 2018, about 2/3rd of December production came from wells that began production in 2018. If you switch ‘Product’ to gas, you’ll find that natural gas production increased to almost 10 Bcf/d, which is even more than is produced in the Haynesville Basin. The final tab shows the production histories of the 5 largest operators of horizontal wells. They all have strongly increased output in the past 2 years, and are at or near production highs. The ‘Advanced Insights’ presentation is displayed below: This “Ultimate recovery” overview shows the average production rate for these wells, plotted against their cumulative recovery. Wells are grouped by the quarter in which production started. The wells that started in Q2 2016 (dark brown curve) have now recovered the most oil, with just over 200,000 barrels of oil produced on average. Newer wells are on a slightly higher trajectory. In the 2nd tab you’ll find all counties in the Permian, ranked by cumulative production, from horizontal wells since 2008. Reeves has taken over the 1st spot from Lea County, with 340 million barrels of oil cumulative production. Close to half a million barrels of oil per day were produced in Reeves in December. Later this week we will have a post on the Eagle Ford, followed by an update on all covered states in the US early next week.   Production data is subject to revisions. Note that a significant portion of production in the Permian comes from vertical wells and/or wells that started production before 2008, which are excluded from these presentations. For these presentations, I used data gathered from the following sources: Texas RRC. Oil production is estimated for individual wells, based on a number of sources, such as lease & pending production data, well completion & inactivity reports, regular well tests, and oil proration data. OCD in New Mexico. Individual well production data is provided. FracFocus.org   Visit our blog to read the full post and use the interactive dashboards to gain more insight http://bit.ly/2I0WJhy   Follow us on Social Media: Twitter: @ShaleProfile
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Utah – update through January 2019

These interactive presentations contain the latest oil & gas production data from all 424 horizontal wells in Utah that started production since 2008, through January. Visit ShaleProfile blog to explore the full interactive dashboard We’ve just included Utah in our coverage of horizontal drilling in the U.S., bringing the total number of covered states to 12. These 12 states are responsible for 99% of recent horizontal drilling activity based on the Baker Hughes horizontal rig count. Although the absolute amount of oil & gas produced in this state is relatively is low, compared with the other basins you’ve read about here, the growth rate has been pretty high in the past 2 years. Oil production from horizontal wells was 33 thousand bo/d in January this year, while it was only 14 thousand bo/d 2 years earlier. Activity during this period has been concentrated in Duchesne and Uintah County, heart of the Uinta Basin.   This growth coincided with a major increase in well productivity, as you’ll see in the ‘Well quality’ overview. New wells recover on average 130 thousand barrels of oil in the first year on production, more than double the amount from wells that began production before 2016.   The final tab shows the top operators in this state. Newfield, the leading operator, has just been acquired by Calgary-based Encana. It has always been the most active player here. The number 2, Crescent Point Energy, showed a big increase in production in 2017. It also has its HQ in Calgary.   The ‘Advanced Insights’ presentation is displayed below: This “Ultimate recovery” overview shows how all these horizontal wells are heading towards their ultimate recovery, with wells grouped by the year in which production started. Also here the major increase in well productivity since 2016 is visible. Newer wells are on a path to recover about 300 thousand barrels of oil before hitting a level of 10 bo/d. Of course there are also major differences here between the operators. If you only select Axia Energy, using the “Operator” selection, you’ll find that its wells are far above average.   It therefore clearly ranks as the best performing operator (see the 4th tab, ‘Productivity ranking’), as measured for example by the average amount of oil recovered in the first year. But the best 2 wells so far are operated by Wesco Operating, as you’ll find in the 2nd tab (‘Cumulative production ranking’). They recovered each close to 1 million barrels of oil so far. We will from now on include Utah in the monthly US post.   Next week we plan to have updates on the Permian and the Eagle Ford. For these presentations, I used data gathered from the following sources: Utah Division of Oil, Gas and Mining Automated Geographic Reference Center of Utah. FracFocus.org   Visit our blog to read the full post and use the interactive dashboards to gain more insight http://bit.ly/2Wnnelk   Follow us on Social Media: Twitter: @ShaleProfile
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Marcellus (PA) – update through January 2019

This interactive presentation contains the latest gas (and a little oil) production data, from all 8,747 horizontal wells in Pennsylvania that started producing since 2010, through January. Visit ShaleProfile blog to explore the full interactive dashboard Gas production in Pennsylvania started this year at a record 18.3 Bcf/d, with a y-o-y growth of 2.5 Bcf/d (16%).   In 2018 10% more wells began production compared with the year before (828 vs. 748) and, as you can find in the ‘Well quality’ tab, they peaked at a 16% higher rate (11,900 Mcf/d vs. 10,300 Mcf/d), on average.   The 2 largest natural gas producers in the state, Cabot and Chesapeake, started the year both with a new production record (“Top operators”). The ‘Advanced Insights’ presentation is displayed below: This “Ultimate Return” overview shows the relationship between gas production rates and cumulative gas production, averaged for all horizontal wells that began production in a certain quarter. The 195 horizontal wells that came online in Q4 2018 (blue curve at the top) peaked at the highest rate ever, 13,700 Mcf/d, which was also double the peak rate of the wells that started 5 years earlier (Q4 2013). Those 372 wells have now recovered 4.6 Bcf of natural gas each and they are still flowing at 1,200 Mcf/d, on average.   In the 4th tab operators are ranked by their average well productivity, as measured by the cumulative gas production in the first year on production. Cabot, which is active in a very prolific area in Susquehanna County, comes out on top, with an average result of 3.3 Bcf in the first year. If you only select 2017 (using the “first production year” selection), this result further increases to almost 5 Bcf.   Later this week we plan to have a post on a new state! Next week, we’ll show again the latest production data for the Permian and the Eagle Ford. Production data is subject to revisions. For this presentation, I used data gathered from the following sources: Pennsylvania Department of Environmental Protection FracFocus.org   Visit our blog to read the full post and use the interactive dashboards to gain more insight http://bit.ly/2HT6oa6   Follow us on Social Media: Twitter: @ShaleProfile
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Gazprom to supply 200 BCM of gas/year to Europe in 2019

Minsk, Belarus. March 22, 2019 Gazprom is planning to maintain its gas supply to Europe at the level of 200 billion cubic meters (BCM) of gas per year in 2019, A. Kruglov, Gazprom board deputy chairman, told reporters on March 22, 2019. Gazprom reached volumes of export supplies above 200 BCM of gas per year for the first time in 2018 and now intends to at least maintain this level. On February 26, 2019, on Investor Day in Hong Kong, Ye. Burmistrova, director of Gazprom Export, stated confidently that Gazprom could maintain exports to Europe at 200 BCM/year for a number of years to come. It is interesting that A. Kruglov assumed that gas exports to non-CIS countries could grow by about 20%, to more than 242 BCM/year by 2025, taking into account the achievement of the planned volumes of gas supplies to China at 38 BCM/year via the Power of Siberia-1 gas pipeline. The key issue is the gas supply situation in 2019, as the new export gas pipelines Nord Stream 2, the Turk Stream, and Power of Siberia-1 are to be launched at the end of 2019. In this connection, reaching a level of more than 200 BCM/year in 2020 is not a problem, but one cannot be sure about Gazprom’s ability to reach this level in 2019, especially with the warm weather in Europe leading to a reduction in gas demand. In the period from January 1 to March 15, 2019, Gazprom has reduced its gas supply to non-CIS countries by 8.2% when compared to the gas supply volumes for these 2.5 months in 2018, to 40.8 BCM. In 2018, Gazprom increased gas exports to non-CIS countries by 3.8% compared with its 2017 exports, to 201.8 BCM. The company was planning to increase this to 204.5BCM/year (the maximum annual contract volume for all export contracts to non-CIS countries), but the export volumes were lower than expected. Gazprom increased its gas production by 5.7% in 2018 when compared to 2017, to 497.6 BCM. In 2019, the Russian gas giant is planning to produce 495.1 BCM of gas, which is a 0.5% decrease from 2018. This is traditional for Gazprom, which usually adheres to a conservative and self-restrained approach when making production forecasts at the beginning of each year. During the year, the forecast for production volumes may be adjusted depending on the market situation.

North Dakota – update through January 2019

These interactive presentations contain the latest oil & gas production data from all 14,469 horizontal wells in North Dakota that started production since 2005, through January. Visit ShaleProfile blog to explore the full interactive dashboard January oil production in North Dakota was unchanged from the month before, at 1.4 million barrels of oil per day. In January, which is typically a slow month, just 85 wells started production. The growth in natural gas production has been steeper in the past few years. Compared with January 2015, natural gas production rose by 88%, versus 18% for oil. The reason for this is that almost all wells experience a rising gas oil ratio, and even stronger for newer wells.   In the ‘Well quality’ tab, you’ll find the production profiles for all these wells. After several years of improving initial well productivity, the 2018 vintage eked out another small gain.   All 5 leading operators in North Dakota started the year at a higher production level than a year earlier (“Top operators”). Continental Resources was the first operator in the history of the state to reach 200 thousand barrels of oil production capacity in January. It doubled its output in the past 2 years. From our analytics service (Professional), we can see how Continental Resources has changed its completion practices in the last couple of years:   In this dashboard we can see that Continental Resources did not change the length of its laterals by much since 2013 (yellow curve), but it did almost quadruple the amount of proppant used, from 3 million pounds per completion in 2013, to 12 million pounds in 2017/2018 (shown by the pink curve). The impact that this had on the amount of oil recovered in the first 12 months is shown in the plots on the right side; the bottom plot shows the same information, but now normalized by lateral length (1,000 feet).   The ‘Advanced Insights’ presentation is displayed below: This “Ultimate recovery” overview shows how all these horizontal wells are heading towards their ultimate recovery, with wells grouped by the year in which production started. The almost 1,800 horizontal wells that started in 2012 have now recovered just above 200 thousand barrels, and are now producing at a rate of 40 bo/d, on average. The 971 wells that started 5 years later (2017) are, with an average recovery of 175 thousand barrels of oil after 14 months on production, not far behind, and they are still operating at a rate of 227 bo/d.   Early next week we will have an update on gas production in Pennsylvania, which just released January production data as well (already available in our subscription services!). It just set another record at over 18 Bcf/d.   For these presentations, I used data gathered from the following sources: DMR of North Dakota. These presentations only show the production from horizontal wells; a small amount (about 40 kbo/d) is produced from conventional vertical wells. FracFocus.org   Visit our blog to read the full post and use the interactive dashboards to gain more insight http://bit.ly/2ueHidA   Follow us on Social Media: Twitter: @ShaleProfile
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Russia’s Gazprombank leaves Venezuela. Rosneft still stays.

Russia’s Gazprombank leaves Venezuela. Rosneft still stays.   Moscow, Russia. March 15, 2019 Gazprombank is minimizing risks in Venezuela. The bank has sold a 17% stake in GPB Global Resources which, in turn, owns 40% of Petrozamora, a joint venture with PDVSA, Reuters stated on March 14. The bank has confirmed the fact of leaving the joint venture without specifying any details. Petrozamora was founded in 2012 to develop oil fields in Venezuela. In 2013, Gazprombank, GPB, Petrozamora, and PDVSA agreed to allocate up to $1 billion for the development of the joint venture. Now, Gazprombank does not have any investment projects in Venezuela.  Rosneft has become the only Russian company with large assets there, Kommersant noted. According to Reuters, the Russian giant oil company has lost about $9 billion on its investments in Venezuela since 2010. Rosneft is running five projects in Venezuela while producing a small share of its total oil production. The crisis in Venezuela involves the risk that the country will not be able to pay its debts. Back in 2011, more than 66% of the Neftegaz.Ru survey respondents approved the participation of Russian companies in the development of the Orinoco fields. However, right now, this heavy and highly viscous oil that the fields have produced remains unsold, as buyers have become hesitant toward purchasing sanctioned oil. Over 8 billion barrels of crude oil are now stored in offshore oil tankers, as the onshore oil terminals are full. If the situation is not improved, we can expect Russian companies in Venezuela to report serious problems. Moreover, these problems are already there. The excess of Venezuela’s oil supply has slowed down work on the Orinoco Belt, including projects for modernizing production facilities – projects which Rosneft is conducting in a joint venture with PDVSA. Rosneft has a share in five joint ventures: PetroVictoria, Petromiranda, Petromonagas, Boqueron, and Petroperija. The international rating agency Moody’s said the US sanctions against PDVSA would limit the financial and operational flexibility of Rosneft’s joint ventures in Venezuela since PDVSA owns more than 50% of each one of them. As is known, Washington has posed large-scale sanctions against PDVSA designed to limit the export of Venezuelan oil and to force President Nicholas Maduro to resign. Russia is among the countries that continue to support Maduro. Over the past few years, the Russian Federation has become Venezuela’s last resort in terms of lenders. According to Reuters estimates, the Russian government and state-owned Rosneft have lent Venezuela at least $17 billion since 2006. Dmitry Peskov, Spokesman for the Russian President, said on March 1 that no negotiations on new financial support for Venezuela were being conducted at the presidential level, but Russia continued to maintain contacts with its partners in Venezuela. “We are interested in continuing cooperation with Venezuela — especially as a number of our companies are running fairly large projects there. We hope that these projects have good potential, that they will have the potential for expansion, and of course, we wish the Venezuelan partners to cope with the difficulties they are facing, both political and economic ones, as soon as possible,” Peskov told reporters.        

US - update through November 2018

This interactive presentation contains the latest oil & gas production data from 99,579 horizontal wells in 10 US states, through November 2018. Cumulative oil and gas production from these wells reached 10.1 Gbo and 109 Tcf. West Virginia and Ohio are deselected in most dashboards, as they have a greater reporting lag. Oklahoma is for now only available in our subscription services. Visit ShaleProfile blog to explore the full interactive dashboard November oil production from these wells will come in at close to 6.5 million bo/d, after upcoming revisions. The number of well completions in 2018 through November was more than 20% higher, compared with the same period a year earlier.   The production profiles for all these wells can be found in the ‘Well quality’ tab. The major oil basins are selected and the performance is averaged for all the wells that started in a particular year. Well productivity clearly rose every year since 2011, with again a minor improvement in 2018.   The total oil & gas production from the 5 largest operators can be viewed in the final tab. EOG produced in November almost double the amount of oil as the number 2, ConocoPhillips. They all significantly increased production in 2018. The ‘Advanced Insights’ presentation is displayed below: This “Ultimate recovery” overview shows the relationship between production rates and cumulative production over time. The oil basins are preselected and the wells are grouped by the year in which production started. As the curves on this plot demonstrate, the decline behavior of these wells is typically quite predictable. By extrapolating them until a certain economic limit, you can make a reasonable estimate of ultimate recovery. You can also do so for your favorite operator, and/or basin, just by selecting them using the filters. The 5,338 wells that started in 2016 recovered just over 150 thousand barrels of oil in the first 2 years on production, on average, as well as 0.5 Bcf of natural gas (switch ‘Product’ to gas to see that). This constitutes a decline of ~82% in these 2 years (from 516 bo/d to 93 bo/d). We are happy to see that The Wall Street Journal has also started to use our services, with this article (behind a paywall): Chevron, Exxon Mobil Tighten Their Grip on Fracking.   Early next week we will have a new post on North Dakota, which will soon release January production data. Production data is subject to revisions. For these presentations, I used data gathered from the sources listed below. FracFocus.org Colorado Oil & Gas Conservation Commission Louisiana Department of Natural Resources. Similar as in Texas, lease/unit production is allocated over wells in order to estimate their individual production histories. Montana Board of Oil and Gas New Mexico Oil Conservation Commission North Dakota Department of Natural Resources Ohio Department of Natural Resources Pennsylvania Department of Environmental Protection Texas Railroad Commission. Individual well production is estimated through the allocation of lease production data over the wells in a lease, and from pending lease production data. West Virginia Department of Environmental Protection West Virginia Geological & Economical Survey Wyoming Oil & Gas Conservation Commission   Visit our blog to read the full post and use the interactive dashboards to gain more insight http://bit.ly/2F6dk1B Follow us on Social Media: Twitter: @ShaleProfile
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Eagle Ford - update through November 2018

This interactive presentation contains the latest oil & gas production data from all 22,019 horizontal wells in the Eagle Ford region, that started producing since 2008, through November. Visit ShaleProfile blog to explore the full interactive dashboard Oil production in the Eagle Ford during 2018 stayed within a few percents of the 1.3 million bo/d level set in December 2017, and I expect that to hold also after upcoming upward revisions. Through November, operators completed 10% more wells than in the same period in 2017.   Well productivity hasn’t changed much in the past year, as you can easily see in the bottom graph of the ‘Well quality’ tab.   All leading operators were off their peak production in November (see ‘Top operators’), although EOG & ConocoPhillips only marginally so. The ‘Advanced Insights’ presentation is displayed below: In this “Ultimate Recovery” overview, the relationship between production rates and cumulative production is revealed. Wells are grouped by the year in which production started. So far most oil has been recovered by the 4,465 wells that started in 2014; they are now at 155 thousand barrels of oil and at a flow rate of 31 bo/d, on average. Newer wells are on a path to recover about 30 thousand barrels of oil more once they hit the same level. We have seen quite some interest in the Austin Chalk formation in this area. Production is increasing, although from a small base. This screenshot, from our advanced analytics service, compares the performance of wells in the Austin Chalk and the Eagle Ford, for the 2015-2017 vintages, with only oil wells selected.   Clearly, recent Austin Chalk wells are outperforming those in the Eagle Ford. Early next week we will have a post covering data from 10 states in the US.   Production data is subject to revisions, especially for the last few months. For this presentation, I used data gathered from the following sources: Texas RRC. Production data is provided on lease level. Individual well production data is estimated from a range of data sources, including regular well tests, and pending lease reports. FracFocus.org Visit our blog to read the full post and use the interactive dashboards to gain more insight http://bit.ly/2VChWlm   Follow us on Social Media: Twitter: @ShaleProfile
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Permian – update through November 2018

These interactive presentations contain the latest oil & gas production data from all 19,047 horizontal wells in the Permian (Texas & New Mexico) that started producing since 2008/2009, through November. Visit ShaleProfile blog to explore the full interactive dashboard November oil production came in above 3 million bo/d (after revisions), at a y-o-y growth rate of 1 million bo/d. More than 4,200 horizontal wells were completed in 2018 through November, double the number in the same period in 2016.   Average well productivity has only increased slightly since 2016, after big gains in the years before, as the ‘Well quality’ tab shows.   The 2 largest producers, Pioneer Natural Resources & Concho Resources, are now above 250 thousand bo/d of operated capacity (see “Top operators”). The ‘Advanced Insights’ presentation is displayed below: This “Ultimate recovery” overview shows the average production rate for these wells, plotted against their cumulative recovery. Wells are grouped by the year in which production started. If you extrapolate these curves, you’ll find that recent wells (2016/2017) are on a path to recover on average about 300 thousand barrels of oil, before their production rate has fallen to 40 bo/d. Associated gas production is high in the Permian, at well over 9 Bcf/d. If you switch ‘Product’ to gas, you can find the average gas production for the same wells. Newer wells are on average likely to recover 1.5 Bcf of natural gas or more.   Today (Tuesday) at noon (EST) we will also present an update on the Permian and the Eagle Ford on enelyst, where we will share our insights in these basins based on the latest data. Last month many of you subscribed to our analytics service, which offers access to more dashboards, well data, and more recent production data. Thank you! The cheapest subscription version, Analyst, costs just $52/month per user, and you can try it for 1 month for only $19. With this, you will experience some of the analytical power of ShaleProfile Analytics.   Later this week we will have a post on the Eagle Ford. Production data is subject to revisions. Note that a significant portion of production in the Permian comes from vertical wells and/or wells that started production before 2008, which are excluded from these presentations. For these presentations, I used data gathered from the following sources: Texas RRC. Oil production is estimated for individual wells, based on a number of sources, such as lease & pending production data, well completion & inactivity reports, regular well tests, and oil proration data. OCD in New Mexico. Individual well production data is provided. FracFocus.org   Visit our blog to read the full post and use the interactive dashboards to gain more insight http://bit.ly/2HgILaR   Follow us on Social Media: Twitter: @ShaleProfile
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Marcellus (PA) – update through December 2018

This interactive presentation contains the latest gas (and a little oil) production data, from all 8,706 horizontal wells in Pennsylvania that started producing since 2010, through December. Visit ShaleProfile blog to explore the full interactive dashboard Gas production in Pennsylvania ended last year at over 18 Bcf/d, with a y-o-y growth rate of 2 Bcf/d. This was the result of the addition of 6.8 Bcf/d from the just over 800 horizontal wells that started production in 2018, minus the 4.8 Bcf/d decline from legacy wells. Such a large contribution from new wells (6.8 Bcf/d in a year) has not been seen before in Pennsylvania. A major factor behind this result is the increase in well stimulation. Newer wells are completed with over 18 million pounds of proppant on average per well, versus less than 14 million pounds per well in 2017. In our ShaleProfile Analytics service, you can analyze this by operator, or even by well.   Initial well productivity improved again in 2018, as you’ll find in the top chart in the ‘Well quality’ tab. The bottom chart shows that wells that started production in 2017 are on a path to recover 4 Bcf of natural gas in the first 2 years on production. The 2018 vintage has even a slightly better start.   The 5 largest natural gas producers in Pennsylvania produced each more than 1.5 Bcf/d at the end of 2018. Cabot is in the lead, with 2.7 Bcf/d of operated output. The ‘Advanced Insights’ presentation is displayed below: This “Ultimate Return” overview shows the relationship between gas production rates and cumulative gas production, averaged for all horizontal wells that came online in a certain year. The 1,188 horizontal wells that started production in 2014 have on average recovered most natural gas, at just over 4 Bcf. They also appear to be on a path to recover more than the wells from the following 2 years. But the wells that have started production since 2017 clearly have a better start, peaking at over 10,000 Mcf/d on average.   In the 5th tab (‘Productivity over time’), you’ll find in more detail how well performance has changed over time. If you change the metric to measure the cumulative gas production in the first 3 months (instead of 24 months), you’ll note that, according to this metric, well productivity has more than tripled in the past 8 years. Newer wells recover on average 0.9 Bcf in the first 3 (calendar) months on production. For wells in Susquehanna County, this is even above 1.5 Bcf (use the ‘County’ selection to filter on this county). By the middle of next week, we will have a new post on the Permian. Production data is subject to revisions. For this presentation, I used data gathered from the following sources: Pennsylvania Department of Environmental Protection FracFocus.org Visit our blog to read the full post and use the interactive dashboards to gain more insight http://bit.ly/2ExomN0   Follow us on Social Media: Twitter: @ShaleProfile
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What if the Oil Business did this?...

What if the oil and gas industry could find capital without giving up large chunks of equity, dancing to a banker's tune or having to go out and raise capital in non-conventional methods? What if the price of oil didn't play havoc with every financing decision made?  Who can call the floor on prices?  Oil executives are handcuffing themselves to believe that higher prices are coming, try to second guess the market and are hamstrung by the proverbial 'paralysis by analysis.' What if we didn't see the decline in prices impacted by computer-driven models?  What if the true value of oil and gas were represented by real time trading and fundamental factors versus declines that were more technical in nature? What if producers that have capital needs could have their production bought over a three to four year time frame and have that oil or gas paid for up front to generate the much needed capital they seek? What if there would be someone out there to absorb this 'time-risk' for a term and get the producer the money they need for re-works, PUD drilling, debt pay-down etc.? What if the producer had the capability of getting this capital off balance sheet, non-recourse, no debt and no equity relinquishment?  What if there were tax benefits thrown in as well? What if the producer maintains total control and participates in 100% of the upside by using this capital? What if the biggest risk in the transaction was delivery risk? What if the capital was easy to access and could close the transactions in 45 days or less? What if we talk about this?  

North Dakota – update through December 2018

These interactive presentations contain the latest oil & gas production data from all 14,383 horizontal wells in North Dakota that started production since 2005, through December. Visit ShaleProfile blog to explore the full interactive dashboard Oil production in North Dakota increased by almost 2% m-o-m to just over 1.4 million barrels of oil per day in December, after a small drop in November. In December 121 wells started production, vs. 98 in November. Although the number of wells that started production in 2018 was more than a thousand fewer than in 2014 (1,266 vs. 2,276), they contributed more production at the end of the year (630 kbo/d, vs 595 kbo/d in Dec 2014).   The reason behind this is that initial well productivity greatly increased over these years, as is shown in the ‘Well quality’ tab. The wells that started in 2018 are on a path to recover just over 170 thousand barrels of oil in the first year, while this was below 100 thousand barrels for the wells from 2014. One major difference between these 2 vintages was the amount of proppant used; 4.5 million pounds per completion in 2014, vs. 10 million pounds per completion in 2018.   All the top 5 operators are at or near record production levels (“Top operators”). The ‘Advanced Insights’ presentation is displayed below: This “Ultimate recovery” overview shows how all these horizontal wells are heading towards their ultimate recovery, with wells grouped by the quarter in which production started. As you can see, the best initial performance so far came from wells that started in Q3 2017. The 271 wells that started in that quarter recovered on average 207 thousand barrels of oil in the first 16 months, and have now declined to 191 bo/d, from a peak rate of 719 bo/d. If you switch product to ‘gas’, you can find the gas production from the same wells. What is striking is that newer wells produce way more gas than older ones (I estimate up to 3 times more). As gas is not earning a lot of money in North Dakota, I advice to be aware of this when looking at production metrics in this basin that use ‘BOE’ (barrels of oil equivalent). Is this rising GOR having an impact on well productivity? On a large scale, the impact seems to be currently limited. However, in some areas well performance seems to suffer from this. As an example, find here the wells from Oasis in McKenzie County, from our analytics service. I preselected a couple of quarters, to show how well behavior has changed since 2011.   The location of these wells is shown on the map on the left. On the right side, you will find the flow rate vs. cumulative plot, and the GOR vs. cumulative plot at the bottom. It shows that the wells from Q2 2011 are on a path to recover most oil, even though the more recent wells started at a far higher peak rate. The steepening of the decline seems to correlate with the rise in GOR. As I mentioned last week, we now have data from Oklahoma in our database, which is available to all our analytics and data subscribers. I would like to make this data also available here on the blog. But because we spent a significant amount of money and time on this, I would first like to see that our customer base has grown even further. My promise to you is this; once we have added 100 more Professional (or Ultimate, once this level is available) analytics subscribers, I will include Oklahoma in our blog posts here. How can you help? Maybe you find use in the more advanced features of these services or know people who might. Please let them know about us, and hopefully we can soon share this data with you here. Thank you for supporting us! Early next week we will have an update on gas production in Pennsylvania.   For these presentations, I used data gathered from the following sources: DMR of North Dakota. These presentations only show the production from horizontal wells; a small amount (about 40 kbo/d) is produced from conventional vertical wells. FracFocus.org   Visit our blog to read the full post and use the interactive dashboards to gain more insight http://bit.ly/2MR9Mme   Follow us on Social Media: Twitter: @ShaleProfile
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US - update through October 2018

This interactive presentation contains the latest oil & gas production data from 98,450 horizontal wells in 10 US states, through October 2018. Cumulative oil and gas production from these wells reached 9.9 Gbo and 108 Tcf. West Virginia and Ohio are deselected in most dashboards, as they have a greater reporting lag. Visit ShaleProfile blog to explore the full interactive dashboard Later this post I will be making 3 major announcements; about a new (and cheap!) analytics service, Oklahoma, and the NAPE. But first, how has shale oil production developed in the past year? You will find in the graph above that all these horizontal wells produced 6.2 million barrels of oil per day in October, which after revisions will be a few percents higher still. More than half of total oil production came from wells that started in 2018, as indicated by the dark blue area. Over 20% more wells were completed in the first 10 months 2018, compared with the same period a year earlier.   Initial well productivity increased slightly further in 2018, as you’ll find in the ‘Well quality’ tab, where all the oily basins have been preselected.   All the 5 top shale producers were at, or near, production highs in October (“Top operators”). The ‘Advanced Insights’ presentation is displayed below:   This “Ultimate recovery” overview shows the relationship between production rates and cumulative production over time. The oil basins are preselected and the wells are grouped by the quarter in which production started. Peak rates have steadily moved higher over the years, as you’ll see here. In Q3 2018, the average peak rate was 668 bo/d, versus 285 bo/d 7 years earlier. Extrapolating these curves allows you to make a reasonable estimate of the ultimate recovery range. You can switch ‘Product’ to natural gas, to do the same for the gas stream of these wells. Today we have 3 major announcements to make: A new analytics subscription level is now available, ShaleProfile Analytics – Analyst, For just $52 per month you can always get access to the latest data, see the exact location of more than 100,000 horizontal wells, and their production history. Most dashboards can be viewed full-screen, and you will have more filtering options, such as between oil & gas wells. If you have been a follower of the blog, and want to stay even more informed, this may be something for you. You can try out this service for the first month for just $19. We almost lose money on this subscription, so don’t wait too long! Oklahoma is in now! Oklahoma has so far been the big missing state in our database. By having it in, we now cover around 98% of all the horizontal wells in the US. It has been a tough state to work with, as data sources are unreliable and incomplete. We have spent a big amount of effort (and $) to add it. There are still some data issues to sort out, but we believe we can already now call it at least a 90% version. There is a greater lag time for Oklahoma than for most other states; we can currently cover production data through March 2018. Try out one of our subscriptions to get access to all this data! Today the NAPE conference here in Houston will start for real. Come visit our booth (#2331) if you have the opportunity, and I’ll show you what we can do for you. Early next week we will have a new post on North Dakota, which will release December data later this week. Production data is subject to revisions. For these presentations, I used data gathered from the sources listed below. FracFocus.org Colorado Oil & Gas Conservation Commission Louisiana Department of Natural Resources. Similar as in Texas, lease/unit production is allocated over wells in order to estimate their individual production histories. Montana Board of Oil and Gas New Mexico Oil Conservation Commission North Dakota Department of Natural Resources Ohio Department of Natural Resources Pennsylvania Department of Environmental Protection Texas Railroad Commission. Individual well production is estimated through the allocation of lease production data over the wells in a lease, and from pending lease production data. West Virginia Department of Environmental Protection West Virginia Geological & Economical Survey Wyoming Oil & Gas Conservation Commission   Visit our blog to read the full post and use the interactive dashboards to gain more insight http://bit.ly/2MR9Mme   Follow us on Social Media: Twitter: @ShaleProfile
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A Special Place in Hell for Brexiters-Donald Tusk

Brexiters hit back at Tusk for commenting that they deserve a special place in Hell for Brexit happening without a deal. Welsh first minister says it would be a catastrophe for Wales if Brexit happens without a plan. Nearly 5 m British and EU people could be stuck in Limbo if Brexit happens without a deal, though Brexiters hit back saying it's  an insult to 17.4 m who voted for Brexit and want apology from Tusk.

Sukumar Ray

Sukumar Ray

Permian – update through October 2018

These interactive presentations contain the latest oil & gas production data from all 18,480 horizontal wells in the Permian (Texas & New Mexico) that started producing since 2008/2009, through October. Visit ShaleProfile blog to explore the full interactive dashboard Oil production in the Permian kept rising at a rate of ~1 million bo/d y-o-y through October. I expect that after revisions total output topped 3 million bo/d. That also means that almost 60% of October oil production came from wells that started in 2018, as is visualized in the graph above. Gas production has seen a very similar growth path, and is now over 9 Bcf/d (switch ‘Product’ to gas to see this).   Despite increased completion activity, well productivity has still slightly increased since 2016, as you’ll find in the ‘Well quality’ tab. Recent wells are on a path to recover on average around 200 thousand barrels of oil in the first 2 years on production. Important factors behind this increase in well performance are longer laterals, and bigger frac jobs. The following screenshot, from our ShaleProfile Analytics service, shows that average cumulative oil production in the six months rose on both sides of the state border since 2012. Interestingly, results are on average better in New Mexico, even though laterals are shorter and proppant loadings are smaller. The final tab shows that all 5 leading operators have roughly tripled their output in the past 3 years. The ‘Advanced Insights’ presentation is displayed below: This “Ultimate recovery” overview shows the average production rate for these wells, plotted against their cumulative recovery. Wells are grouped by the quarter in which production started. Initial well productivity has kept rising through the last quarters. The more than 1,000 wells that started in Q3 last year peaked over 800 bo/d in their first full calendar month. Let’s also take a look at the terminal decline in this basin, as we did in our last 2 posts, even though the average well age is much younger here. I again used the ‘Terminal decline’ dashboard from our Professional Analytics service. See here the result: The performance is shown of all the horizontal oil wells in the Permian, that started production between 2011 and 2014. Only wells are selected that fell below a production rate of 60 bo/d not later than May 2016 (this ensures that we have at least 30 months of data for all wells), from which they never recovered. There were 3,183 such wells, from in total 6,065 horizontal oil wells that started in the Permian in these 4 years. The top chart shows the oil production rate (logarithmic scale) of these wells, by the number of months since they fell below 60 bo/d. The wells are grouped by the year in which they started. The bottom chart shows the average annual decline, calculated based on the plot above. If you have also seen the previous 2 posts, you’ll note that terminal decline rates are lower here than in the DJ Basin & the Eagle Ford. The decline rates drop to a level between 15 and 25%, before they stabilize or start to increase again. As noted above, data after 30 months is not complete (not all wells have more historical data). Also here you’ll see that younger wells experience larger decline rates. Again I would like to emphasize that part of that is expected, as they earlier in their hyperbolic decline curve, where decline rates are naturally higher. But it still appears that even if you correct for that, younger wells decline faster. Likely there are several effects in play, such as changing economic limits & completion designs and more infill drilling. As more and more wells enter this phase, this could increase the decline rate of the whole population (e.g. a certain vintage), negatively impacting EURs and reserves. If you have any thoughts on this topic, please share them below in the comments section.   Next week we are at the NAPE summit in Houston, so if you happen to be there, please come visit our booth (#2331). We still have time available earlier in the week for 1-on-1 meetings in Houston, so please contact us if you’re interested in understanding how we might help you.   Early next week we will have a post on all 10 covered states in the US. We also plan to launch a new (cheaper!) version of our Analytics service then. Production data is subject to revisions. Note that a significant portion of production in the Permian comes from vertical wells and/or wells that started production before 2008, which are excluded from these presentations.   For these presentations, I used data gathered from the following sources: Texas RRC. Oil production is estimated for individual wells, based on a number of sources, such as lease & pending production data, well completion & inactivity reports, regular well tests and oil proration data. OCD in New Mexico. Individual well production data is provided. FracFocus.org Visit our blog to read the full post and use the interactive dashboards to gain more insight http://bit.ly/2MR9Mme   Follow us on Social Media: Twitter: @ShaleProfile
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