Long, cold winter emphasizes need for energy transition plan

Long, cold winter emphasizes need for energy transition plan

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Long, cold winter emphasizes need for energy transition plan

Energy prices skyrocket going into winter as the U.S. energy industry is experiencing another market swing. While there is no clear-cut plan moving forward, there are things that can be done in the near-term. 

Once again, the demand for energy is exceeding supply resulting in increased energy prices in the U.S. Demand for energy is up due to several reasons including disruptions in the supply chain, an economy emerging from 18 months of Covid, weather extremes and plan old poor planning. But the main cause may be the decreased investing in oil and gas companies resulting in a supply shortage.  

Whenever there is an increase in energy demand, the question ultimately arises on renewables verses oil and gas. According to this recent article from Fareed Zakaria, in the Washington Post, there is no current overall plan for a transition to a renewables-based energy supply. The result is a confusing U.S. energy policy where we are now asking OPEC to increase production when we have some of the world’s largest reserves of oil and gas! 

While more domestic drilling will help with supply, we can also look at reducing emissions in the short-term. For example, convert the 5% of older fossil-fuel plants responsible for 73% of emissions. And decrease the 70% of methane leakage from O&G wells that can be stopped by using existing technology.  

Renegade is expertly positioned to help stop the methane leakage problem. These flow paths to the surface typically occur in older and abandoned wells and compromise wellbore integrity. This has long plagued oil and gas wells, especially in abandoned wells where methane leaks are common and present an environmental risk. This includes the thousands of ‘orphan’ wells seeping methane that will need to be treated in the future before they are plugged and abandoned. 

Local Expander™ technology from Renegade can safely and effectively seal the annulus without damaging the casing and stop methane from escaping to the surface. The key to this innovation is a set of expanding fingers that open outward once the tool is actuated downhole. This unique technology expands the casing into the cement, densifying the cement and blocking the path of any unwanted gas flow.   

Local Expander Renegade

Renegade Wireline Services is the largest independent provider of cased-hole electric wireline services  and is recognized as the premier cased-hole completions service provider in the North American oil and gas industry. Renegade offers professional, experienced personnel with a cased-hole and radioactive tagging focus working in an efficient and safe manner to produce operational excellence and customer satisfaction. 

Local Expander™

Let’s start the conversation about how Renegade and the Local Expander can work for you.

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The Northeastern, PA district was the first Renegade district opening in 2009. The innovations brought forth by this safety-minded district helped pave way for RigLock’s successful launch and prosperity of their industry reputation as a reliable company delivering what is needed to keep things running smoothly at all times while also being among those leading technological change with years’ worth experience using eline or slick line equipment respectively.  NEPA was an early adopter of slick line, eline and greaseless line boasting years of experience in the field. Utilizing Aradia we provide fast and automated stage work, while having an exceptional skillset in logging, slick line and pump down stage work.

NORTHEASTERN, PA

Renegade Wireline Services

MAILING & PHYSICAL:
54 Nadalini Dr
Mansfield, PA 16933

PHONE:(570) 545-5500

Admin:
Stephanie Servatius | sservatius@renegadewls.com

Sales:
Rodney Offield | roffield@renegadewls.com
Tyler Smith | tsmith@renegadewls.com

District Manager:
Josh Burt| jburt@renegadewls.com

 

NORTHEASTERN PA

NORTHEASTERN, PA
54 Nadalini Dr
Mansfield, PA 16933
(570) 545-5500

Complete Oilfield Services Provider in Northeastern, PA

A Service Company Take on 2020 Projections – Permian, Bakken, Marcellus

As we wrap up this decade, we take a look back in the oil & gas industry and reflect on the contrasting cycles. There were periods of fruitful gain for some and throbbing pain for others. This year was a great reflection of the decade, exhibiting both boom and bust cycles in time that some have flagged as peak domestic production and the “height” of the great shale revolution.

That doesn’t mean the suffering is over by any means! The 2020 horizon will undoubtedly bring regulatory change, capex alterations, and supply & demand fluctuations that have few companies excited, and some optimistically cautious hoping that it’s a year of transition leading to better times ahead.

If you made it here, you may or may not have been looking for any given topic relating to 2020 projections, forecasts, outlooks, insights, analyses, predictions, recommendations, or planning, to name a few. Whatever it was that got you here, welcome! We have compiled a list of all things oil and gas in 2020 to serve as a quick reference list to all that new year oil & gas development goodness.

Happy Holidays!

-The Renegade Team


Table of Contents

CapEx 2020

Hart Energy Operator Profile 2020

Shale Experts Capital Expenditure Database
(Subscription required)

2020 Outlook & Forecasts

Hart Energy Production Forecast

McKinsey 2020 Oil & Gas Outlook

Deloitte 2020 Oil, Gas, and Chemical Industry Outlook

Forbes Growth In U.S. Natural Gas Production Should Slow In 2020

Enverus Crude Forecasts

EIA Short Term Energy Outlook

IHS Markit 2020 Outlook

OFS 2020 Outlook

 

 


CapEx 2020

Hart Energy Key Players Shale Producer Profiles

Hart has put together a nice profile of the top 43 shale producers in the US. Each operator has a short profile of size and shape metrics like production, rig & frac crew count, acreage, and planned capex totals or percentage change from the previous year. Each profile has a link to the latest investor update which we have shortcut here:

Antero
Apache
Ascent
BPX
Cabot
Centennial
Chesapeake
Chevron
Chief
Cimarex
CNX
Concho
ConocoPhillips
Continental
Devon
Diamondback Energy
Encana
Endeavor
EOG
EQT
Equinor
FourPoint Energy
Hess
HighPoint Resources
Lewis Energy
Laredo Petroleum
Marathon
Matador
Mewbourne Oil
Murphy
Noble
Oasis Petroleum
Oxy
Parsley Energy
PDC
Pioneer Natural Resources
QEP
Range
Shell
SM Energy
SWN
Whiting Petroleum
WPX

The Renegade Take:

There is still an awful lot of new development that will take place next year. Some budgets may be lower than last year, but most budgets seem to be fairly strong to keep production up. We think that adaptations to technology-based systems and practices as the efficiency movement in drilling & completions will remain a key driver of the services market. Conventional assets particularly offshore may see a boost in activity in the coming year too.


Shale Experts Capital Expenditure Database

(Subscription required)

A phenomenal resource compiling major oil & gas producer spending data broken down by capital types including: Total capex, drilling & completion budgets, infrastructure and facilities budgets, and land budgets.

 

The Renegade Take:

We have our fingers crossed that next year volatility drops and operations stabilize for more than the short-term.


2020 Outlook & Forecasts

Hart Energy Oil And Gas Production Forecast: 2020 And Beyond

Hart Energy & Enverus (formerly DrillingInfo) have put together an analysis of 2020 forecast and displaying trends in areas such as permitting, engineering, operators, midstream, and more. Additionally, the analysis breaks down the drying up of capital investment resulting in slowed growth and sustainable operations from free cash flow generation. There are many macro-view breakdowns of basin specific analysis showcased here through the Enverus platform.

 Source: Enverus

The Renegade Take: 

Common theme here is to find efficiency gains even with a reduced budget to drive returns on capital. Spending the least amount while sustaining production can only come from one place – technology adoption!

 

 Source: Enverus


McKinsey 2020 Oil & Gas Outlook

Longer term outlook from MicKinsey streamlining 2018 growth through 2035. Most notable prediction here is the layout of a global recession coupled with OPEC negotiations and price support even with high US production and lower-breakevens.


Deloitte 2020 Oil, Gas, and Chemical Industry Outlook

Forecasting a market balance with slightly lower US shale production coupled with OPEC cuts that give some much needed stability to producers and investors alike.


Forbes Growth In U.S. Natural Gas Production Should Slow In 2020

An analysis by JTC Energy Research Associates highlighting the realities of sustained low gas prices relative to the realities of our dependence on them as a nation.

 

The Renegade Take:

Gas prices could use a sustained uptick. We will help support any way we can.


Enverus – Four Crude Forecasts That Caught Our Attention at the Energy Trading Risk Summit

Pricing scenarios based on current metrics of exports, operator guidance, and what the world is willing to absorb.


EIA Short Term Energy Outlook

Always a good resource to have as a reference on a regular basis.


IHS Markit 2020 Outlook

Growth will finally slowdown according to IHS Markit.

Going from nearly 2 million barrels per day annual growth in 2018, an all-time global record, to essentially no growth by 2021 makes it pretty clear that this is a new era of moderation for shale producers,” said Raoul LeBlanc VP for North American unconventionals, IHS Markit, “This is a dramatic shift after several years where annual growth of more than one million barrels per day was the norm.”


OFS 2020 Outlook

From Rystad Energy, a recent report outlines how low oil prices could cause a slight recession in oilfield services from double digit growth this year to single-digit growth in 2020. Additionally, 2021 looks to rebound from a slight dip in the action.

 

The Renegade Take:

We are hopeful that with higher oil prices that services will remain steady in the coming year with projects scheduled to be consistent throughout the course of the year.

Thank you for reading! Stayed tuned for more updates as reports come out during the last few weeks of the year.

-Renegade Services

DISCLAIMER: Renegade Services remains a neutral-party to all of other companies referenced in any blog post listed on our website. The opinions in any blog post do not necessarily reflect the views, opinions, or position of Renegade Services at any point beyond our current time of publishing.

For more information, call us now on (806) 568-0042 or use the form below:

  • Company Name
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Holiday PSA – Don’t Cut Corners on an Irreplaceable Service

Holiday PSA – Don’t Cut Corners on an Irreplaceable Service

Let’s face it, the fingers are starting to fly. Interdisciplinary teams handing off capital projects at different stages of planning and completion intervals involves well-rooted trust in one another, particularly from the management team. The trade-off of engineering decisions relative to acceptable risk as they relate to growth and investment return appears to be tipping a three-dimensional scale in the wake of added pressure from capital markets.

As we all look back and reflect on the rollercoaster of the industry through the last few years, it’s easy to look back and only see the flaws. At this point, the only thing that can be done to prevent animosity in the future is to continue to make environmental and profit-tied decisions within each specific program.

We would like to quickly hit on some points that have been hot topics in the last month1

Completion Engineers and Managers have been under the microscope for decisions made in the last few years of field development by the investor community. On one hand, it is easy to see the argument that investors are making “growth mode” eventually convert to dishing out real returns. On the other, engineering teams are struggling to continue making sizable gains between cost-cutting, maximizing depletion, and transitioning the cohesive plan from growth to cruising altitude at this point in the optimize-or-die game.

The continual cost-cutting environment of completions programs appears to be at an inflection point of diminishing returns if programs start ditching foundational services (and adjoining service quality).

Understandably, some of the services on a per well or per pad basis (whatever operator x chooses for a unit economics model) are difficult to justify on a risk-adjusted basis to put in the starting rotation if they no longer definitively improve production. This new, “new normal” shift, in our opinion, will put greater focus on wireline services not only being the most cost-effective value-add service, but also one that will be hit with a second pack of watchdogs. High levels of accuracy, transparency, and service quality are poised to be the renewed delicacy in completion services as we move forward. And although we may all start out as relatively similar, we certainly do not finish that way. The choice among wireline companies is one wrought with weathered competition, but few stand out as organizations where all service personnel conduct daily operations as owners. We get it – building a machine churns systemic value back to your company and borrowed investor dollars couldn’t be more mission-critical right now, and we can alleviate the stressful uncertainty of wireline services consistency and quality.

The way to wright the ship is through trusted service partners. With core & non-core services to support ‘tidal’ programs, set your bearing and navigate the service of wireline on a straightened path. Entrepreneurial integrity is invaluable when so many variables can impact any given process on any given well, field, and/or basin. Traditional services don’t mean dated, they are simply elemental to execution.

Whatever round of revisions you’re circling around (again), we hope reading this can realign perspective in seeing a more direct path to lean operations without sacrificing value. Wireline is not created equal and high-caliber services might just be tomorrow’s secret sauce that’s right under your nose. When you’re ready,  ☎️ us.

Sources

1. www.linkedin.com

DISCLAIMER: Renegade Services remains a neutral-party to all of other companies referenced in any blog post listed on our website. The opinions in any blog post do not necessarily reflect the views, opinions, or position of Renegade Services at any point beyond our current time of publishing.

For more information, call us now on 281-603-9720 or use the form below:

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New Appalachian Gas Estimates Support Decades of Development

New Appalachian Gas Estimates Support Decades of Development

This week the United States Geological Survey (USGS) released a geology-based study stating that the Appalachian Basin holds an estimated 214 Tcf of undiscovered, technically recoverable reserves. This span includes the Marcellus, Point Pleasant, and Utica formations from Ohio, Pennsylvania, West Virginia, Virginia, New York, Maryland, Kentucky, and New York 1.

The report is up from the last 2011-12 estimates where the bulk of the increase in reserves comes from the Utica-Point Pleasant numbers being up over 300%.

In 2018, Pennsylvania alone produced 6.1 Tcf of gas2 and is the second-largest domestic producer of gas behind Texas. Production has grown year over year despite suppressed gas prices over the last decade.

Map of Assessment Units (AU) in Appalachia | Renegade Services

Regardless of how feasible the macro reserve estimates at any given timeline of projected depletion, it is safe to say that at current levels of production there will be steady work for years to come. The trend of well sites in Appalachia pad sizing to maximize well counts while minimizing its footprint definitively pushes the density of productivity in the region. It is our estimation that this density will be the driving force behind operators adopting technology that fosters efficiency and automating repetitive tasks.

Looking beyond siloed segments of the upstream industry, we at Renegade take a lot of pride in spearheading product development in the oilfield. Multi-functional engineered equipment is future of consolidating operations and introducing automation best practices to an industry that has been overlooked for years in this regard. With this in mind, we look at the production system with a holistic viewpoint. In addition to our suite of upstream products and services, we are excited about the growth of our production services. Our newest product, CET, is set to be a household name in well intervention later in the well life as well as after abandonment. With the record gas production in the northeast, as well as other basins in the country or continent for that matter, we see our Casing Expansion Tool as the leading intervention tool to provide the most immediate results for the lowest cost.

We have a lot to be excited about here at Renegade.

The United States has proven itself in the to be a sustained production leader through innovative thinking and hard work. In order to prevent a plateau because of a stall in technology adoption that either becomes cumulatively too expensive or doesn’t drive the industry forward, we believe that giving time for newer technology that has directly measurable results to blossom. We are excited to see what 2020 brings and look forward to working with anyone committed to taking automated development from a discussion to a line item in an AFE that is relied on well after well.

DISCLAIMER: Renegade Services remains a neutral-party to all of other companies referenced in any blog post listed on our website. The opinions in any blog post do not necessarily reflect the views, opinions, or position of Renegade Services at any point beyond our current time of publishing.

For more information, call us now on 281-603-9720 or use the form below:

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0.16% Methane Leak Occurrence Rate of Collaborative US Production in 2019

0.16% Methane Leak Occurrence Rate of Collaborative US Production in 2019

As the US has grown oil and gas production to record levels, interdisciplinary parties have expressed concern with the current administration’s decision to reduce regulations governing methane processing on well-sites.

The Environmental Partnership1, a cohort of 65 oil & gas production companies, representing every basin in the US (and globe for that matter), with the simple mission of collectively monitoring and reducing air emissions, including methane and VOCs.

Their mission statement is:

To continuously improve the industry’s environmental performance by taking action, learning about best practices and technologies, and fostering collaboration in order to responsibly develop our nation’s essential natural gas and oil resources.

Even with the US dry gas production totals in 2018 exceeding 30,438 bcf annually, up from 27,291 bcf per day in 2017, it is impressive that the leak rate from surface equipment is 0.16% and decreasing with continued best practices efforts across 78,000 well locations 2, 3.

In those efforts, there is a strong emphasis on implementing latest leak detection technologies (including portable), replacing pneumatic bleeding devices that make little to no effort to process vent gas, and improving processes involving the manual transfer of liquids from wells. The Environmental Partnership and companies within it agree that they all can continue to drive the number of leaks down further with on-going participation.

The Environmental Partnership Emissions | Renegade Services

Figure 1. The Environmental Partnership Emissions Source Chart via EPA2.

In conclusion of the report, it is great to see the industry collective being as proactive as possible in this initiative. We would like to use this opportunity to go one step further and look at the complications involved with downhole leaking. Unwanted issues of gas getting to surface through micro-annuli behind casing and fractures in casing causing leaks can present unwanted processing concerns that take away from typical production operations.

Our Local Expansion Tool™ is a cost-effective solution that can have repeated services applied through the length of a wellbore without leaving any deployable tools downhole. The simple crimping of casing to close the annuli gap and strengthening casing has been found to eliminate surface casing vent flow and sustained casing pressure situations.

Adding a downhole dimension to The Environmental Partnership with efforts toward eliminating downhole venting in the most cost-effective way possible is a discussion we would love to have! We know this is a solution the industry has been demanding for some time now and we want to cement our legacy in gas containment and pioneering responsible industry practices.

DISCLAIMER: Renegade Services remains a neutral-party to all of other companies referenced in any blog post listed on our website. The opinions in any blog post do not necessarily reflect the views, opinions, or position of Renegade Services at any point beyond our current time of publishing.
For more information, call us now on 281-603-9720 or use the form below:

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Calling All The Shots – Angling into the Winning Combination of Capital Budgets in 2020

Calling All The Shots – Angling into the Winning Combination of Capital Budgets in 2020

In a newsletter article from back in August from Rystad Energy titled “US Shale Operators Manage to Raise Targets yet Stay Thrifty”1, they take a look back at 2Q19 and look at the shift from the beginning of the years front-heavy capex spending to how production has influenced capex changes for Q3 and Q4. The group of analyst determined that because of the second half of 2019 will be carried by production volumes and lower costs to drive cash flow, they found that most of the operators had an unchanged capital budget or a slight reduction in capex spending. The prominent outlier in the trend is ConocoPhillips, who are adding a rig to their Eagle Ford fleet and increasing capex spending in the basin to add $100M in 3Q19. Nonetheless, the direction of the industry according to Rystad data is the decrease in spending for the second half of the year, where the largest cuts appear to be made by pure-play operators, with the highest density of cuts centered around the Permian.

In this week’s article, we are looking at the trends from this summer and looking at how they panned out during the fall. There is a fine line when production is at record highs and investors are calling for capital discipline that results in a better return. We will draw conclusions from public reports to shape an outline of 3Q19 and the remainder of the year, as well as projections as to the beginning of the year, trade tensions, and the competition for market share.

One notable chart from the Rystad report is the comparison of budget cuts from actual spending in the first half of the year overlaid with the implied expectation of the second half.

Figure 1. Rystad Energy Capex Comparison in 2019 | Renegade Services

Figure 1. Rystad Energy Capex Comparison in 2019

From what we know about which operators make up their contribution to the overall production number, and excluding operators that have had issues with takeaway capacity constraints, we will focus this analysis on the majors, larger producers, and those that are nearly split on capital cost throughout the midpoint of the year or have more of a back-loaded capex plan. Regardless of when each operator decided to execute their 2019 plan, most of which are on track to meet discretionary goals set this time last year and maintain, or grow free cash flows. An anomaly of the group, as we found, Halcon Resources did file for chapter 11 around the same time that this report was published by Rystad which might add some color to their ‘straight-line’ path story with all else held constant on 2019 capex programs.

As of June of this year, ShaleProfile has listed the top 5 producers in the US of crude oil are EOG, COP, Pioneer, Concho, and Anadarko2. In order of capex already spent, Anadarko leads the group in capex spent while producing the least amount per day (269,183 b/d from 3,619 active wells). We know, however, that Oxy closed on Anadarko August 8th, also around the same time as this report, which could have impacted their capex spending as the the deal value closed in on $38B. Comparatively speaking, Anadarko’s next closest peer in as a non-major multi-basin operator, EOG, has spent about one-third of the capex for the year and is the leading oil producer in the US adding 567,777 b/d of production from 6,855 active wells. On a per well basis, Anadarko produces about 85 b/d while EOG produces 83 b/d.

Figure 2. ShaleProfile interactive chart displaying top 5 oil producers in the US in June 2019 | Renegade Services

Figure 2. ShaleProfile interactive chart displaying top 5 oil producers in the US in June 2019.

Interestingly, ConocoPhillips lower 48 onshore production is largely outside of the Permian basin, as is EOG, and they hold the silver and gold metals for June 2019 production respectively. COP stood head and shoulders above the crowd by adding that additional $100M in capex after picking up the Eagle Ford rig, where almost every other operator except for a major and a few very large oil and gas producers added to the spending and continued working deep into the calendar year. COP also leads the charge in productivity averaging 122 boe/d from 2,353 wells and a cumulative daily production of 288,267 b/d overall.

Now that we have some landscape work taken care of, let’s look at how this applies to automating the completions operations subset to produce measurable, investable savings.

Looking at the August Investor report from COP3, they are in line with what most shale operators have dissented upon during the ‘awakening’ phase of the shale boom from 2014 to the present – higher density sand per foot and increasing the number of clusters was an easy way to scale until it became imperative to pair the sand concentration design with each individual stage. Conoco claims to have seen a roughly 30% increase in production from 2012 to 2017-current in a series of 4 iterations of completion design changes.

Now, as cheerleaders for operators realizing their potential for surface efficiency gains in addition to production and financial growth, their lower 48 operations are absolutely ripe for adopting completion hardware automation technology that can safely bring on more wells in any given year solely from Automated Frac Equipment™ (AFE™) among other products and services we offer.

Again, glaring example is Conoco picking up an additional Eagle Ford rig for 3Q19 and 4Q19. Armed with the ability to produce a handful more pads by year end could be a healthy cushion to boost cash from operations (CFO) and create additional CFO to continue to grow the company while affordably paying dividends, share buybacks, and overall smoothing out the cyclical nature of the business. Within reasonable expectations, 2020 is poised to be a high production year with plenty of takeaway capacity flooding the global market with supply. An advantageous way to infill a program with new D&C wells or bring DUC wells online in a more rapid fashion, AFE™ can deliver foundational efficiency simply through quick toggle times between operations resulting in 3-5 more stages per day in a safer way than current methods. We think this could be its own line item next year on the 3Q2020 version of the “Continuous Learning and Optimization of Completions Drives Value” slide! COP is scheduled to issue a third quarter update on October 29th, we will come back to them in a few weeks.

Circling back to EOG. This group boasts a decentralized, non-bureaucratic, and most importantly, innovative and entrepreneurial group where the value each team member as a business person first. Like others, low cost, self-sourcing, and execution is the name of the game of disciplined results and returns. In their 2Q19 update they list the following IT components that drive their company into a highly organic growth machine and exemplify the following as pillars to their success: real-time data capture, large proprietary data warehouses, predictive analytics, 100+ in-house apps, and fast/continuous technology advancement4. Honestly, it’s not every day you see that much detail (and it isn’t even that much) on what technology means to them printed in an update. For the Permian-centered Wolfcamp stack, has seen an 8% increase in 1H19 completed lateral feet per day, doing from 1,030 feet per day to 1,110 feet per day, and a subsequent 12% increase in 90-day cumulative production in this interval from all of 2018 (normalized from 7,000ft laterals). Technology-driven operator, meet a technology driven service provider. In their entire US portfolio of assets, EOG is scheduled to complete approximately 725 wells in 2019. You don’t have to be data driven to fathom the mountain of moving parts to make this single metric happen.

We say – eliminate some of them. 85% of all the dumb iron can be eliminated with AFE™, and 30 minute rig up times are the new reality – no mini-cranes or one-dimensional equipment here. Switch from wireline to frac in minutes with RigLock®. Machine operated wireline handling & rebuilding rather than by hand with GunHandler™. Smart equipment to match the mentality of data driven operators of scale. We challenge you to see the difference optimizing surface operations can have on your production by being able to orchestrate your mobile outdoor factory in a calibrated, automated fashion.

Figure 3. An EOG rig in Laramie County, WY in April 2019. Source: Wyoming News5 | Renegade Services

Figure 3. An EOG rig in Laramie County, WY in April 2019. Source: Wyoming News5

Looking at the gas production end of the spectrum, the Rice-EQT merger followed by the successful proxy battle led by the stiff arm of the Rice brothers to take control of EQT and implement some serious changes in an effort to create a real synergy with a bandolier of robust assets. 8 new board members, a 100-day plan, and a well stoked fire is sweet music to our ears6. Having said that, we realize that since the time of the last investor update the 100 days is nearly up. Better late than never right? The core of our business is consolidating, digitizing, and automating overlooked oilfield equipment and processes. There is no better way to optimizations than by removing manual human labor and old fashioned iron with remote controlled, multi-axis and programmable stinger coupled between the missile and wellhead. When well intervention is needed or backside casing pressure requires attention, we have a suite of simpler, faster technologies that frankly do not exist elsewhere and at a fractional cost to what is out there. In addition to high-bleed pneumatic replacement, consider our Casing Expansion Tool (CET™).

We know there are plenty more of you operators out there doing incredible things for our industry, its investors, and the surrounding communities and environment. As we get to a place where capacity comes online to significantly increase our overall production, the battle for top spot in production for both oil and gas will result in being up to our eyeballs in gross production, keeping prices and sustainability fragile in the face of volatility. As renewables are steadily gaining market share as energy producers, it ultimately puts pressure on our sector to continually keep costs low and responsibly manage assets for the long term. While renewables simply can’t replace the impenetrable value oil & gas provides to everyday life, it can keep us honest and stay on track to be able to keep developing this vital resource and minimize political backlash and division. We strongly believe our technologies systematically fit into the digital transformation we are witnessing in the shale revolution today. In order to hit goals over the long term, operationally, financially, and responsibly, we don’t foresee any possible outcomes where our equipment and services aren’t utilized short of the industry coming to a grinding halt.

Shed some of that weight onto us. Let us help facilitate change within your organization. We as much as any market participants want to see this industry succeed in all the right ways. We are here as a resource to anyone who can see our value that you yourselves say you continually seek. Don’t let 2020 completion plans off the hook too soon – you can take a lot of slack out of the line with technology-driven completion equipment.

-Renegade Services

 

 

Sources

  1. https://www.rystadenergy.com/newsevents/news/newsletters/UsArchive/shale-newsletter-aug-2019
  2. https://shaleprofile.com/2019/10/08/us-update-through-june-2019
  3. https://static.conocophillips.com/files/resources/2019-investor-update-08012019.pdf
  4. https://investors.eogresources.com/Cache/1001255228.PDF?O=PDF&T=&Y=&D=&FID=1001255228&iid=4075407
  5. https://www.wyomingnews.com/news/local_news/wyoming-cheyenne-continue-steady-economic-growth/article_0e69b3a5-c488-5624-bf97-50c96c794837.html
  6. https://s24.q4cdn.com/922296017/files/doc_presentations/EQT_Analyst_Presentation_-_July_25_2019.pdf

DISCLAIMER: Renegade Services remains a neutral-party to all of other companies referenced in any blog post listed on our website. The opinions in any blog post do not necessarily reflect the views, opinions, or position of Renegade Services at any point beyond our current time of publishing.

For more information, call us now on 281-603-9720 or use the form below:

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Part 1 – Analytics from Aerial Imagery – A Time-based Approach to Evaluating Efficiency

Part 1 – Analytics from Aerial Imagery – A Time-based Approach to Evaluating Efficiency

It’s that time of year again. Budget season has started to wind down as we head into October. Frac crews are starting to get released as we cut from the year highs back in April of 482 active spreads to now around 395. Although around one-third of the total domestic count is located in and around the Permian basin, it was estimated that about 25 spreads were released this week1. Even with more crude oil long-haul lines coming online in West Texas headed for the Gulf of Mexico at the end of this year and into 2020, an end-of-year annual slowdown will be met with highly anticipated shipping commitments of operators that have not yet fully opened the floodgates. Furthermore, a year end shift in Caribbean refining capacity to supply to the east coast ongoing supply constraints is the light at the end of the tunnel for the upstream holiday siesta2

In Part 1 of this blog series, we are taking advantage of this time to look back at how the industry fared in 2019 thus far. Growing pains for technology adoption in US completions have sparked an on-going debate about whether or not some design changes add efficiency & production gains, or simply additional costs with no production enhancements to offset the effort and dollars required to make juice worth the squeeze.

We will show how we derive a dataset from aerial images and compare with the timeline of filing data to get a sense of time between the start and end times of drilling and completions. Also from our set of data, we can make accurate estimations on beneficiaries of efficiency-based surface equipment that could be a driving factor in time and cost savings when things pick back up again. Other data pulled for this analysis are from the Texas RRC3, FracFocus4, WellDatabase5, and the EIA6. The satellite images and coordinate derivation is from Bird.i7.

Permian – The Pulse of US Production Growth

The drastic growth in US oil and gas production has been a result of the industry focus shifting toward the low cost Permian basin after the downturn. In fact, over half of the US Production is sourced from the Permian8. With the high levels of production, the Permian also now produces and flares more gas than the daily residential gas consumption demand9. caused largely by the lack of sustained takeaway capacity, including gathering infrastructure.

Large operators have since dominated the basin and the ability to produce at lower commodity prices and commit to long-haul takeaway contracts. While they await infrastructure, the DUC well count has continued to grow over the years and the spread between drilling and completing wells can often be delayed depending on pricing, availability of crews, materials, equipment, etc. With the newly minted infrastructure, however, comes the burden to fulfill their capacity contract. In theory, as drilling rigs continue to build efficiency and produce the same amount of new wells with a decreasing fleet of rigs, this could be the eve of a the DUC well inventory to start to show a sharper decline.

To keep production constant, we believe that the cycle times between operations, services, and drilling locations will see continued attention to detail, helping both the operational side of the business as well as the financial side. We are confident that the market will see our offerings as a cost-effective, value-adding, and time-saving bundle that can help them stand apart from the producer pack.

 

 

Figure 1. 2019 Permian Drilling, Completion, and Production Trends. Source: EIA Data, Texas RRC, and WellDatabase

 

 

Ahead of the Curve (From Above)

As a service provider focused on continually improving, our goal is to facilitate the transition to operational drivers through the adoption of technology. Delivering best-in-class equipment and services that consolidate legacy standard operating procedures into a turnkey package is something we think adds true value during this interval of growing pains.

Nonetheless, we also like keeping an eye on what’s going on around town (go figure!). Just as operators look for an edge and take the latest and greatest tools of the trade out for a spin, Renegade Services gets the keys every now and then as well. Gone are the days of getting coffee at Anytown Oilfield, USA diner and you come away with a tally book full of fresh leads on XYZ operator is doing next (or NOT doing in the coming months). The tools of the trade are becoming much more advanced, to where they are in-fact, ‘out-of-this-world’. 

Having these extra resources is inherently valuable. Taking a look into satellite images from Google Earth is often helpful for navigating lease roads in West Texas, but not necessarily helpful in the latest activity. More often than not, images and subsequent data from readily available geographical software can be more than multiple years old depending on your area of focus. Imagine using some of these thinking you’re capitalizing on a new idea (cue Homer Simpson annoyed grunt sounds, aka “D’oh!”). 

Scanning for pad development, frac ponds construction, lease roads, staging areas, and pipeline construction to name a few of the attributes we search for to anticipate upcoming activity and better service operators in the area. In the image below taken from earlier this month, current activity in the area shows serious signs of life compared to its standard Google Earth predecessor. It is also noteworthy to look at the surrounding activity of work that has been completed a few months prior. Going back and evaluating surrounding infrastructure after initial production rates have been published can often give a much clearer picture of activity in the immediate and local areas.

 

Figure 2. An early September peek into an active frac fleet in the Delaware Basin. Source: Bird.i.

Actionable Real-Time Monitoring

History has shown us that it’s much more likely that the second mouse gets the cheese. We are not the pioneers of this technology and we are certainly not the first in the industry to attempt to wrangle this niche and use it to our advantage. Following in the footsteps of operators that use this tool to keep an eye on their neighbors and the overall basin, weekly or sometimes daily uploads of photos are extremely valuable in reasonably monitoring real-time progress.

Being able to track the latest operator moves, however, can be done without having to wait on weekly team meetings and investor reports to be posted. Utilizing filings as cross-references as leading and lagging indicators, tracking progress directly in the field enables us to grow as our clients, (and potential client) do.

Extremely small teams can make research efforts take a matter of hours when it used to take weeks for entire teams to comb, digest, and analyze geospatial data into something more user-friendly. Being a proactive service company frees up our team to focusing more on innovation and efficiency on the well site, and less on project timing. 

Conclusions

Keeping up with the Jones’s is a real thing in today’s technology world. On one hand, it seems like the oilfield is catching up to tech innovations like a post-thanksgiving half-marathon. On the other hand, those embracing the change appear to be making more risk-adjusted decisions that seamlessly mesh and enable faster growth. Building algorithms using existing transformative datasets that can free up capacity within our operational teams is huge for us, and our customers.

The trade off from efforts put into developing this technology is certain to streamline leads, and keep shop teams privy to anticipating the next dispatch. We are excited to see how this helps facilitate growth as we finish up 2019 and start into 2020.

 

Stay tuned for Part 2 of the series where we map out a detailed series of time-based change on areas of interest and monitor change from a distance. 

 

 

 

 

Sources

  1.   https://blogs.pvmic.com/tag/frac-spread-count/
  2. https://rbnenergy.com/welcome-to-the-jungle-part-2-limetree-bay-restart-can-help-east-coast-product-balance
  3. https://rrc.texas.gov/oil-and-gas/research-and-statistics/drilling-information/monthly-drilling-completion-and-plugging-summaries/
  4. https://fracfocus.org/
  5. https://app.welldatabase.com/Browse/Wells
  6. www.eia.gov
  7. https://portal.hibirdi.com/#/imageservice
  8. https://www.eia.gov/petroleum/drilling/#tabs-summary-2
  9. https://www.bloomberg.com/news/articles/2019-04-10/permian-basin-is-flaring-more-gas-than-texas-residents-use-daily

 

DISCLAIMER: Renegade Services remains a neutral-party to all of other companies referenced in any blog post listed on our website. The opinions in any blog post do not necessarily reflect the views, opinions, or position of Renegade Services at any point beyond our current time of publishing.

For more information, call us now on 281-603-9720 or use the form below:

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Where is the intersection of technology advantages and value in the oilfield? A Golden Goose Egg Story

Where is the intersection of technology advantages and value in the oilfield? A Golden Goose Egg Story

Clearly, technology has improved modern life throughout the cycles of the industrial revolution through what we think of technology today1. The line in the sand has seemingly blown away in the wind in terms of the crossover point of growth spending versus return on capital employed. Furthermore, the break-room buzz of investor pain of late has sparked the conversation about really cutting costs across entire programs, changing upstream design for the long term, and influential management styles that keep investors feeling secure (relatively secure, that is)2.

Every service claims to have value that it brings to its particular flavor of the mix. Fact of the matter is, when oil hovers in the $50 range (also known as breakeven for some of you out there), chasing IPs ‘on the next one’, there is no other way out but to stay the course. There appears to be an infinite supply buzz-worthy, golden egg services on the market today that boast the latest way to predict, machine-learn, or hyperbolize production to death via over-application of equipment and services.

A concrete, historically successful practice of automation has led global companies safer and more potent production across numerous industries. The intention of writing this is to hold the light and present a real option that satisfies numerous needs. Not all technology is created equally! As things go from bad to worse through uncertain times, simplify. Deflate the situation by transitioning to a long-term solution that will be difficult to replicate in a new way without taking a step back in time. The modern energy demand requires a modern solution that has instantaneous results that can be observed, measured, and scaled that satisfies the producers’ appetite for technology adaptation and the investors famished for a decent return for their risk effort.

AFE™ is the cornerstone where you can make a change that washes the slate clean of constraints built from a different price era.

If shale is going to be the continued driver of overall production, completion costs, time, and efficiency must change. For comparison’s sake, we don’t envision operators of scale switching from top drive rigs. Why would you? AFE™ is the equivalent mechanical autonomy of the completion side.

Measurable consolidation on surface that will change today’s completions operations from here on out. Think about that. No AI or derivatives of technologies that present illusion of value. When push finally comes to shove, remember a tangible, instantaneous implementation to the oilfield and the investment community will appreciate for years to come.

You will never get stronger without picking up the weights…

– Renegade Services

 

Sources

  1. https://pubs.er.usgs.gov/publication/fs20193050
  2. www.linkedin.com

DISCLAIMER: Renegade Services remains a neutral-party to all of other companies referenced in any blog post listed on our website. The opinions in any blog post do not necessarily reflect the views, opinions, or position of Renegade Services at any point beyond our current time of publishing.

For more information, call us now on 281-603-9720 or use the form below:

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How Upgrading Completion Sites With Automated Frac Equipment Could Lead To A Profitable Industry Turnaround For Q4

How Upgrading Completion Sites With Automated Frac Equipment Could Lead To A Profitable Industry Turnaround For Q4

It goes without saying that the oil and gas sector, as a whole, has underperformed financially in the last year. Since August 1st, the Oil Well Services and Equipment Industry segment is down roughly 13%1. E&P companies haven’t fared much better, and international trade fears have raised a caution flag to growth mode. What are investors to think of the energy sector when poor returns are backed by overcrowded markets, high-operating costs, and operations/management style that is solely focused on what has worked in the past?

Backpedaling a bit, it was 2014, the shale boom was in full swing and oil was well over $100/bbl. From 2010 through most of 2014 (pre-Thanksgiving). Anyone with fresh acreage was gunning to optimize drilling programs and have their rigs output surge all while determining completions best practices and then scale operations from there. While that can work in a high price environment, the downturn left shale producers and service providers across the board hurting for multiple years. The kicker is when prices stabilized, the same mindset was prevalent after any remaining acreage was scoffed up – larger wells results in higher production and growth to get there will be part of the deal until further notice.

After two years of growth, coupled with a strong economy, those outside of oil and gas (and even those within it) have no choice but to scratch their heads. If oil prices are high enough to be profitable, and cost-cutting efforts have driven efficiency, why is the industry as a whole is still not as profitable as before? There are certainly management teams tackling a reduction in operating costs, time, and resources required to achieve investor goals. Tough, risk-adjusted decisions have to be made across E&Ps firms to get the ship turned around and ultimately determine what are the value-added, mission-critical services needed to execute sustainable drilling & completion programs.

Now more than ever is a great time to be honest about capital expenses for the remainder of this year’s program as well as next. We can’t change things like overly tight field development and weaker than expected decline rates. While the optimal basin-specific play is drawn up and framed in the clubhouse, take a look at the other areas of cost savings that you could allocate back to investors. 

A quick peek into the plethora of alternative data sets2 (real-time satellite imaging in this case) will show that overall, the majority of completion sites still have iron pipe nested around every wellhead. Some of you spend billions of dollars per year on well construction to keep production constant or build on what you have and increase it. Understanding the volume of services pledged to subsurface development attributes, it is difficult to understand how surface operations haven’t had a closer look when it’s the easiest thing to see and measure.

Although the straddled cost of iron pipe and standard flange connections seems like an area that is resigned to the ‘way we’ve always done it’ area- think again. Automated Frac Equipment is best in class oilfield automation that has real, efficiency, safety, and cost savings stats for operators that are serious about measurable results that give investors transparent returns. Automated Frac Equipment (AFE) is arguably the most needed piece of equipment in shale development progression right now.

Taking a note from our brothers and sisters in a neighboring industry provides a foundational case study to proving our point. Manufacturing has come a long way from its roots in the industrial revolution. In particular, the automotive sector right near the top of the class for most improved. Early robots in the industry were designed to perform one to two repetitive tasks usually involving assembly or welding. In today’s world, robot arms have up to 12-axis and can work at extremely high rates of speed without sacrificing a spec of accuracy4. If the automotive industry is engineering-out bolt-turning operations for both efficiency and safety reasons on a lower cost per unit operation, how on earth is our industry sufficing to let armies of workers chase leaks and burn time all in a high pressure, high risk, work environment? Name another industry that hasn’t adopted automation technology and was able to scale to modern levels. Billions of dollars of investment in company-wide robotic implementation programs were a major factor in car makers such as the stock price for Ford and General Motors, doubling in the early 1980s, as well as pulling it out of the early 1990s slump5.

We all love the unbelievable resource that shale production has been to the United States and other nations across the globe to keep energy affordable to consumers. We believe that it is imperative that operators (and their investors) look at turnkey ways to improve surface operations since they’re direct and firmly measurable. Not only did we bring a product to market that was in desperate need of reconsideration, but we are also a seasoned service group looking to make a historic impact. We know you won’t look back once you start automating completion sites with robots – other industries haven’t and you won’t either.

Sources:

  1. https://csimarket.com/Industry/Industry_Performance.php?ind=604
  2. https://www.kayrros.com/our-products/ep-operations-intelligence
  3. https://blog.hibirdi.com/oil-gas-mining-sites-from-above
  4. https://www.robotics.org/blog-article.cfm/The-History-of-Robotics-in-the-Automotive-Industry/24

DISCLAIMER: Renegade Services remains a neutral-party to all of other companies referenced in any blog post listed on our website. The opinions in any blog post do not necessarily reflect the views, opinions, or position of Renegade Services at any point beyond our current time of publishing.

For more information, call us now on 281-603-9720 or use the form below:

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A Week of Reflection – Long Term Sustainability as a Whole

A Week of Reflection – Long Term Sustainability as a Whole

“Whaddya Got?”(1)

An iconic ice-breaker to any meeting run by the late T. Boone Pickens is a well-timed snapshot of those walking into the beginning of this chaotic week, unaware of the volatility and uncertainty in global oil and gas markets. In any case, the energy world lost an iconic man last week that embodied what it meant to be an American entrepreneur in the energy business. In his farewell letter, thankfulness, humility, and reflection were the overarching themes. 

We have many things to be thankful for as Americans, with entrepreneurship being a staple. A point that resonated with the core of our company in this letter is to: “Embrace change. Change creates opportunities.” Even though attacks on infrastructure are never welcome, they are in fact a curveball of technology advancement (2). An already sensitive oil & gas sector was certainly agitated and left investors and those outside of our industry with a nervously sour taste in their mouth. IHS estimated that even though foreign markets are unrest, the ripple effect had little impact on US shale production (3). Furthermore, the pricing outlook for 2020 remains optimistic that US producers can operate in a comfortable range of prices that satisfies producers’ needs.

Nevertheless, facilitating change is still a function of technology application. Becoming a more advanced producer, as a country, for the long term, is only as good as the adoption of technology that moves efficiency forward in a cost-effective way. Function, value, safety, security – you name it, it has to be included to engage sustainability and reduction of energy imports. As we navigate through uncertain times in an opinion-filled world, remaining focused on driving operational excellence is what will polish industry investment grading (4). And as transactions rise and fall, they make way for firms to apply expertise from other projects on new higher value developments (5).

Our sentiment this week is to remain hopeful that the future will continue to progress in a way that provides prosperity to those around the world. Well-intentioned communication combined with the creed that we will all “leave it better than we found it” sets the stage for future generations and security of life as we know it for the incumbent. Whatever pocket of the industry you occupy (or outside the industry for that matter), all of you shape the continual dynamic of energy supply and demand. And love it or hate it, modern energy means the integration of all energy sources, sourced from all over the globe. Work ethic, professionalism, and superior technology applications will always prevail as the benchmark of opportunity, and something the US can be proud of as a top energy producer of the world.

SOURCES

1: https://boonepickens.com/?p=2343

2: https://www.bloomberg.com/news/articles/2019-09-14/saudi-aramco-contain-fires-at-facilities-attacked-by-drones

3: https://www.petroleum-economist.com/articles/low-carbon-energy/renewables/2019/the-climate-threat-will-investors-exit-big-oil

DISCLAIMER: Renegade Services remains a neutral-party to all of other companies referenced in any blog post listed on our website. The opinions in any blog post do not necessarily reflect the views, opinions, or position of Renegade Services at any point beyond our current time of publishing.

An Operators Perspective on Safety

An Operators Perspective on Safety

Eliminating the Hazard With GunHandler – The Wireline Tool Wrangler

If there has been one constant in the oilfield over the last century, it’s the backing of a strong and dedicated workforce.

The labor component of oil and gas operations is equally important as is its technology advancement counterpart. The human element of capital, maintenance, and production projects is likely to remain the leader of consistency in the oil patch. Even with modern efforts to digitize and mechanized field operations, having personnel onsite to manage best practices and keep operations continuous is paramount. With the on-going introduction of works, as always, brings a highly variable degree of risk to every step of operations.
The main focus here is the operator. Possibly one of the most laborious positions in the oilfield, operators on a frac spread is no stranger to hard work. Neither are the numerous 3rd-parties coming in and out of location performing various specialty services.   

In the case of wireline operators, they are the ones often to stay on the job from start to finish, being on-call, and being a single point of contact during troubleshooting. Because of the repetitive nature of wireline activities during fracs, wireline operators are subjected to the same repetitive hazard profiles during each work shift.

Slips, trips, and falls, pinch points, overexertion, fire or explosions, exposure to high levels of noise, and struck-by high-pressure line hazards are all commonly associates hazards any given wireline operator (or any operator on location for that matter) would be exposed to during any given shift. While some of these hazards we cannot engineer out of the hierarchy of hazard controls, the repetitive motion of picking up, and laying down wireline tools before and after each stage, there is a lot of room here to eliminate the hazard of manual tool handling, as well as increase efficiency of not tying up other personnel on location. Furthermore, heart rate creep on operators is further minimized as this action has been replaced by the mechanized operation through GunHandler. Elevated heart rate is a during work shifts is a leading cause of accelerated fatigue and fatigue-related injuries.

During ambulatory work bouts spread over a two-week hitch, the average operator heartbeat can be elevated up to 72% of their normal heart rate over the course of 14-15 days. Tight living quarters often filled with industrial noise and frequent interruptions, high-pressure operations that quickly escalate in cost, and the mental toll of being away from home can all lead to a decrease in the capacity to focus on well site operations.

Additionally, GunHandler has a 42-inch deck height to move any tool after assembly or before disassembly away from jack stands on the ground to an optimal waist height level. Rather than using the manual dolly to vertically orient tools for pick up or lay down, GunHandler eliminates the hazards associated manual tool deployment in addition to reducing the contribution to repetitive strain risk facing wireline crews.

All of the Renegade product families attempt to remap today’s wellsites. We pride ourselves on our engineered products and services matching the level of high-expectation operators demand in our tech-driven world. Trying any of our products can be the stability you need in the stress-flush environment of price volatility. We know our debut with new clients will a refreshing experience, and that’s what gets us fired up every morning.

https://www.osha.gov/SLTC/etools/oilandgas/well_completion/well_completion.html

https://www.slideshare.net/PuputAryanto/introduction-to-oil-gas-health-safety-environment

https://renegadewls.com/wireline-services/completions/gunhandler/

DISCLAIMER: Renegade Services remains a neutral-party to all of other companies referenced in any blog post listed on our website. The opinions in any blog post do not necessarily reflect the views, opinions, or position of Renegade Services at any point beyond our current time of publishing.

Contact form submission from fraclock.com

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World Oil ShaleTech™ Hydraulic Fracturing Forum: Summer 2019 – Q & A

World Oil ShaleTech™ Hydraulic Fracturing Forum: Summer 2019 – Q & A

On Thursday, August 22nd, 2019, Scott Van Vuuren, Executive Sales, Automated Frac Equipment,  was the 3rd presenter on the World Oil ShaleTech™ webcast.  Below are the Questions that were asked during the webcast.

Skip to 38:20 for Scott’s presentation.

 

Q: Is there a standard field “pressure testing” protocol for the AFE system once it has been latched to the wellhead, and does it require any specialized training or unique communications protocol with the pressure pumping crew?

A: The control panel and the hydraulic wellhead latch allows a quick test up to 15K. This process will test the latch making sure we have a good connection. Our specialists take a 40-hour class to get certified on the AFE. We communicate directly with the customer and frac supervisor once the latch is tested. At that time frac can pressure up through their iron and the AFE.

 

Q: From the slides, the AFE appears to be a single, trailer-mounted system. Is that correct, and where is the AFE operating console located in relation to the programmable boom?

A: The AFE is a single trailer that is 50 feet long and weighs approximately 88,000 LBS. The AFE has a remote control that is C1D1 rated and can be operated up to 200’ from the unit along with a backup remote on location.  In addition, the AFE has manual controls that can be operated if necessary. The remote allows our specialist to be close to the wellhead during programming to ensure the stinger is entering the latch fully.

 

Q: Scott, you mentioned the remotely operated, programmable boom. From an operations perspective, would you talk about the staging of the AFE on-site, how it interfaces with the frac pumps and manifold system, and how the programmable boom locates and interfaces with the wellheads

A: Prior to the frac, our specialist will meet with the frac coordinator to discuss what connections are needed from the missile to the AFE (Monoline or a goat head), then we will spot equipment in the proper area on location. At that time, we also make sure the hydraulic well connection is installed correctly and torqued up. We then program each wellhead 1,2,3,4 etc. During operations, our specialist remotely moves the AFE to the desired well. For example, if we are on well 1 and are done fracing and we need to go to well 4 our specialist has to hold down 2 buttons on the remote, one for the wellhead the other is a dead man switch. The AFE always returns to “home” prior to going to the next well, this is to prevent the AFE from possibly running into wireline or coil that is rigged up in between.

 

Q: What is the daily rental price of the AFE and HLWA?

A: It’s more affordable than you might think. We’ve designed AFE with cost in mind by making it compatible with equipment most operators are likely to already own. That being said, the rental price varies greatly depending on the circumstances of the site. We can schedule a meeting and discuss your needs and additional benefits with the AFE.

Please reach out.  281-603-9720

 

Q: Can one run a wireline lubricator on top of the latch assembly?

A: Absolutely, the latch is designed to accommodate wireline, coil injection head, and AFE.

 

Q: As a single point of failure how do you plan to support the FracLock with back up equipment?

A: All 60˚ and 90˚ can be replaced in the field within a couple of hours. We send additional 60˚ and 90˚ with the unit. We monitor real-time metal loss during the frac and are able to see when there is 20% wear. We also have a program where we can model the frac and predict possible blowouts.

 

Q: How would one deploy balls….. in the latch.

A: We have a ball drop system that attaches to the hydraulic wellhead assembly.

Please contact me directly for more details. 281-603-9720

 

Q: Scott, how AFE has been received in the field?

A: Several of our customers are waiting for units. They see this as the future of frac, with the AFE it is bringing much more value than just the ability to frac. The reduction of iron, needed manpower, NPT and keeping employees from possible injuries are just a few of the great benefits.

 

Q: Scott, Does the RFE include an isolation valve in the assembly?

A: No not currently.

Long, cold winter emphasizes need for energy transition plan

Radioactive Tracers Offer a Closer Look at Horizontal Completions

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RADIOACTIVE TRACERS OFFER A CLOSER LOOK AT HORIZONTAL COMPLETIONS

Radioactive Tracers Offer a Closer Look at Horizontal Completions, David Holcomb World Oil, November 1991.

ABSTRACT

Completion techniques can be analyzed using gamma ray emitting isotopes and spectral gamma ray logging. Examples of Austin Chalk and Bakken Shale evaluations show how operators can qualitatively compare stimulation and diversion effectiveness, and completion methods by using tracer technology.

Radioactive tracer tagging during stimulation treatments on vertical wells has been in use for many years and applications have been discussed in literature. More recently, multiple radioactive tracers have been employed to help evaluate various aspects of well stimulation. They have become standard industry practice for evaluation of treatment containment, fracture height growth, channeling behind casing, fracture initiation from perforations, diversion, and acid or proppant distribution.

Long, cold winter emphasizes need for energy transition plan

The Determination of Fracture Orientation Using a Directional Gamma Ray Tool

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THE DETERMINATION OF FRACTURE ORIENTATION USING A DIRECTIONAL GAMMA RAY TOOL

The Determination of Fracture Orientation Using a Directional Gamma Ray Tool, J.L. Taylor, III, et al, SPWLA 91-AA, June 1991.

ABSTRACT

The effectiveness of hydraulic fracturing operations is commonly evaluated by tagging the materials pumped downhole with one or more gamma-ray-emitting isotopes and subsequently logging the borehole with a gamma ray spectroscopy tool. Many times it is very desirable to also determine the orientation of the fracture planes. This paper describes a directional gamma ray tool which makes this possible.

The main tool component is a sodium iodide scintillation detector within a rotating tungsten shield containing a slotted aperture. A three-axis accelerometer is used to determine the direction of the gravity vector relative to the tool axis. The 1-11/16-inch-diameter toolstring consists of a gamma ray spectroscopy tool and a directional gamma ray tool. Optionally, a direction gyro survey tool may be attached.

The logging procedure is first to run the spectroscopy tool to determine the distribution of tracers. This allows depth intervals to be selected for stationary measurements and moving runs with the directional tool. Example logs from prototype tool field test illustrate the effectiveness of the directional gamma ray measurements. These results show that many gamma ray maxima exhibit significant azimuthal asymmetry. The interpretations of these asymmetries are discussed and compared with laboratory measurements.

Long, cold winter emphasizes need for energy transition plan

Gamma Ray Tracers Help Evaluate Acid Diversion

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GAMMA RAY TRACERS HELP EVALUATE ACID DIVERSION

Gamma Ray Tracers Help Evaluate Acid Diversion, J.L. Taylor, III, et al, Petroleum Engineer International, February 1990.

ABSTRACT

The use of multiple gamma ray tracers has helped evaluate acid diversion in several North Sea completions. The use of multiple radioactive tracers and subsequent logging with advanced gamma spectroscopy techniques offers a cost-effective and convenient method for direct measurement of vital stimulation parameters such as diverter effectiveness.

Productive intervals in the Norwegian sector of the North Sea tend to be quite thick: Danian pay ranges up to 550 ft, and Maestrichtian up to 500 ft. Average porosity can reach 48%, and matrix permeability varies from less than 0.1 to 5 md. Well productivity seems dependent on the degree of natural fracturing, and pressure transient testing derived permeability estimates can be as much as 75 times the matrix permeabilities obtained from core measurements.

Perforations are placed in 10-to 20-ft clusters spaced 40 to 80 ft apart, with a shot density of 2 shots/ft throughout each cluster. The acid stimulation treatments are then pumped in multiple stages, with each stage consisting of a viscous pad, acid, overflush, and diverter (ball sealers are most often employed).

The tracer studies outlined in this article were conducted on six stimulation treatments to determine if the diverter techniques employed result in relatively even treatment of all pay, and to evidence the creation of multiple hydraulic fractures. All evidence suggests adequate diversion usually occurs and new fractures are propagated on each stage.

The specific tracer technique used involved the placement of a different discernible gamma emitting tracer in each stimulation stage to determine its relative placement and thus infer the effectiveness of the diverter stages. Three tracers, Antimony (124Sb), Iridium (192Ir), and Scandium (46Sc) were added to each stage to differentiate the placement of up to three stages or groups of stages. Following each treatment, a Prism® log was run to identify tracer placement. A detailed description of the materials used and the tagging and logging techniques were discussed in earlier articles.

The tracers were prepared as ceramic particle encapsulations, with a mean particle size of 0.5 mm. This proprietary preparation exhibits a tracer washoff of less than 0.01% in 28% HC1 at 100xC, and has a specific activity of approximately 0.89 mCi/gm (32.8 MBq/gm) or 0.0014 mCi/particle (0.0527 MBq/particle). The use of these tracers in particulate form was preferred to using soluble forms to minimize environmental concerns of returning radioactive residue to the surface with the flowback of the spent acid. The tracers and the equipment used to inject them into the stimulation process were transported to the well platforms from the UK aboard the service company’s vessel performing the treatment. Generally, about 20 mCi (740 MBQ) of each tracer was injected continuously throughout each acid stage. Specific licensing to perform the radioactive tracer studies was required from Norway’s National Institute of Radiation Hygiene.

The wells were logged using a 1.6875-in. (4.2863-cm) OD Prism tool, which contains a 1-in. by 6-in. scintillation crystal. The logging speed was 500 ft/hour (152.4 m/hour). At each 3-in. (7.62 cm) interval, the entire 256-channel gamma ray spectrum was encoded and transmitted to the surface and recorded on magnetic tape. This data was subsequently processed using the proprietary software on a microcomputer at a log analysis center in Stavanger, Norway. The software mathematically unfolds the gamma ray spectrum to determine tracer yields and indicate the location of individual isotopes along the wellbore. Furthermore, the program determines the lateral tracer placement (inside or outside the casing) by using a photopeak to downscatter ratio.

The results of the six tracer studies are presented in tabular form in Table 1. The Prism logs from wells A, B, and C are presented as Figs. 1,2, and 3, respectively.

In summary the following conclusions are made:

Tracer materials of the type and packaging used are effectively placed in the formation and do not flow back into the well. In consequence, reliable Prism data may be obtained in one pass after cleanup flow of the well.
Where the cement bond log indicates effective mechanical isolation of perforated zones in the treated interval and the number of perforations is low, good diversion occurs.Breakdown of both single and multiple zones on individual stages were observed.
Limited fracture heights and formation of multiple fractures occurs.
Tracer material positioned during the early treatment stages is partially stripped away during the later stages. This is particularly apparent when the number of perforations is low and flow velocities will, in consequence, be high.
The logging technique and analysis allows us to determine the placement of isotopes in the presence of radioactive scale.

Long, cold winter emphasizes need for energy transition plan

Tracers Improve Hydraulic Fracturing

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TRACERS IMPROVE HYDRAULIC FRACTURING

Tracers Can Improve Hydraulic Fracturing, J.W. Chisholm, Petroleum Engineer International, July 1989.

ABSTRACT

Because the success of well stimulation treatments often dictates the economic justification of petroleum field development, much effort has been devoted to the measurement of various parameters associated with this critical and costly operation. Specifically, the prediction, measurement, and optimization of induced hydraulic fracture geometry is an endeavor which has resulted in a major industry-wide research effort. in the past 10 years, extraordinary advances have been made and the evolution of well stimulation technology is still proceeding at an incredible rate.

Many methods of actually measuring or inferring fracture geometry during or after a frac treatment have been developed and tested; however, few are considered sufficiently pratical, convenient, and cost-effective to be performed routinely. Analysis of pressure data from frac treatments and prefrac injection tests can lead to quantification of certain fracture parameters such as closure stress, fluid efficiency, and leakoff coefficient; however, computation of most of these properties requires knowledge of the vertical fracture height.

Of all the available vertical fracture height measurement techniques, post-treatment tracer and temperature surveys are by far the most common because they are convenient and relatively inexpensive to conduct. Temperature surveys can provide quantitative vertical fracture height determinations; however, they are plagued by the following problems:

Cross flow and pressure-induced fluid redistribution following the treatment can result in temperature surveys that are difficult to interpret.
In wells where the formation temperature differs only slightly from the surface ambient temperature, these surveys are not possible.
If significant amounts of proppant remain in the wellbore and must be circulated out before logging, the circulation process may distort the temperature anomalies created by the frac treatment, or the temperature anomalies created by the treatment may completely dissipate by the time the temperature survey can be conducted.
Because of these problems, particularly the last, frac treatments are frequently tagged with radioactive tracers. The major objections to using gamma emitting tracers have been that:

Only single tracer operations were pratical, unless tedious multiple logging runs using tracers with greatly differing half-lives were conducted.
A conventional gamma ray log cannot differentiate tracer material actually placed in the formation from residual tracer left in the wellbore; thus, the determination of actual vertical fracture height is often obscured.
The depth of detection from the wellbore is limited to less than a meter unless excessive concentrations of radioactive tracer are employed.

Long, cold winter emphasizes need for energy transition plan

Using Tracers to Evaluate Propped Fracture Width

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USING TRACERS TO EVALUATE PROPPED FRACTURE WIDTH

Using Tracers to Evaluate Propped Fracture Width, S.A. Holditch, David Holcomb, Zillur Rahim, SPE 26922, November 1993.

ABSTRACT

Using Tracers to Evaluate Propped Fracture Width

Many production engineers are beginning to use three-dimensional (3-D) fracture propagation models to design and analyze hydraulic fracture treatments. To use a 3-D model, one must define the layers that comprise the reservoir and develop detailed datasets that accurately describe the layers. The data that are critical for designing and analyzing hydraulic fracture treatments are in-situ stress, formation permeability, formation porosity, reservoir pressure, and Young’s modulus. Many times, these parameters can be determined from logs and/or correlated to lithology.

Once the datasets are obtained, one can use a three-dimensional fracture propagation model to estimate values of created or propped fracture length, width, and height. To understand and improve the fracture design process, the engineer must confirm the estimates of fracture dimensions that are predicted by a fracture propagation model. To verify the model, one must analyze field data to be sure the field data are consistent with the model results. For example, the net pressure predicted by the 3-D fracture propagation model should closely match the net pressures observed in the field. When net pressure is adequately matched, we usually find that the overall created fracture dimensions predicted by a 3-D fracture propagation model are reasonable. To determine estimates of propped fracture length, one must also analyze post-fracture production and pressure transient data. Because of fracture fluid cleanup problems, we often find that values of propped fracture length generated by analyzing field production data are much shorter than the created fracture length predicted by the fracture propagation model. Detailed engineering studies are often required to reconcile the differences.

To directly measure values of fracture width, one must perform a fracture treatment in openhole, then use a downhole imaging tool to “see” the fracture. Such an approach is not usually practical. In this paper, we will describe a method to qualitatively estimate the propped width profile at the borehole that uses radioactive tracers. Confirming the propped width profile generated by a model with field data can be very beneficial and informative.

We have found that the use of zero wash radioactive tracers can help us learn both (1) where the fracture fluid is going and (2) where the proppant resides in the fracture near the wellbore. Assuming the level of radioactivity is proportional to volume, then the level of radioactivity will also be proportional to the propped fracture width. As such, one can obtain qualitative estimates of propped fracture width at the wellbore using a radioactive tracer where the strength of the radioactive signal is proportional to fracture volume near the wellbore.

The objectives of this paper are to discuss what factors control the fracture width profile and how to obtain data to compute fracture width. We also explain how one can use radioactive tracers to develop data that can be analyzed to determine qualitative estimates of propped fracture width. Finally, we provide several examples to illustrate how one can use estimated values to calibrate a 3-Dimensional fracture propagation model.

The information described in this paper can be used by a production engineer to obtain a better understanding of a specific hydraulic fracture treatment. As our understanding of hydraulic fracturing improves, we should be able to design the optimal fracture treatment with more certainty. When we design and pump the optimal fracture treatment, we maximize the economic return on developing oil and gas properties.

Long, cold winter emphasizes need for energy transition plan

Tracers Facilitate Stimulation Job Evaluation

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TRACERS FACILITATE STIMULATION JOB EVALUATION

ABSTRACT

Radioactive Tracers Facilitate Stimulation Job Evaluation

Logging tools can now quantify multiple isotopes, including the volume of individual isotopes present and their radial position away from the wellbore. In conjunction with those improvements, tracers have been developed that eliminate “wash off” effects of conventional tracers. By precisely locating the presence and concentration of traced proppant at the wellbore, better evaluations can be made of vertical and radial proppant distribution near the wellbore and fracture aperture width.

A comprehensive study of 98 wells with 136 fracture stages in four different basins has been completed. Each stage was traced and logged. Spectral gamma ray logs were compared with conventional openhole logs, sonic stress logs where available, and cased hole logs such as cement bond and production logs. This data was then compared on a well-by-well basis with the fracture design program, post treatment stimulation reports, and production history.

Several trends were identified while building this massive stimulation evaluation database. Problems that potentially could be solved using tracer technology are:

  • Fracture height greater than design
  • Unstimulated perforation sets within a stage
  • Understimulated pay intervals

 

Long, cold winter emphasizes need for energy transition plan

Using Tracers For Monitoring And Diagnosing Horizontal Well Stimulations

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USING TRACERS FOR MONITORING AND DIAGNOSING HORIZONTAL WELL STIMULATIONS

ABSTRACT

Using Tracers for Monitoring and Diagnosing Horizontal Well Stimulations, David Holcomb, Robert A. Woodroof, World Oil Horizontal Well Completions Symposium, 1996.

The application of multiple radioactive tracers (Zero Wash®) and spectral gamma ray imaging has allowed for improved diagnostics of stimulation treatment distribution. Whether acidizing and diverting or fracturing and proppant placement, multiple tracers (i.e.; Iridium-192, Scandium-46, Antimony-124) have allowed operators to better analyze proppant entry with respect to stage, volume, and/or type placed across lateral intervals, as well as acid entry and distribution in order to better understand and optimize treatment techniques such as diverting, rates, stage sizes, etc.

Holcomb and Read demonstrated that tracers were useful in evaluating Austin Chalk and Bakken Shale completions in South Texas and North Dakota respectively. Qualitative comparisons helped operators understand stimulation coverage and diversion effectiveness.

Problems still plague the use of tracers in horizontal wells and usually center around uncemented or poorly cemented casing. Tracer materials can accumulate behind pipe in depressions or washed out sections even if acid or slickwater treatments are overflushed. While this may make tracer images more difficult to interpret, it does not rule out their usefulness for identifying potential problem areas. Open hole horizontal completions have also posed problems for tracers due to wash-off of tracer materials and adsorption onto rock, not necessarily associated with fracture entry. Improvements made in horizontal well drilling and completions have been aided by the reliability of improved Zero Wash® tracer carriers and spectral imaging tools to provide a more quantitative look at stimulation treatment placement across horizontal well sections without the problems associated with wash-off and subsequent adsorption onto rock, casin, liners, etc.

One particular application has been noted with tracers used to confirm the success or failure of various diverting techniques to allow lateral zones to be completely acidized. Different Zero Wash® tracers are placed in different stages of acid separated by various diverter stages using such materials as oil soluble resins, gel pills, ball sealers, benzoic acid, rock salt, crushed Unibeads®, or foams. Three tracers are usually used in a variety of carrier sizes, densities, and non-wash/crush/abrasion-loss formats. They include Iridium-192, Scandium-46, and Antimony-124, with half-lives varying from sixty to eighty-four days.