Introducing: The Primary Vision National & Granular ReFrac Report

Refracturing treatments (“refracing”) has the potential to have major impacts for operators, oilfield service companies, and their suppliers. Initial evidence indicates refracing can reduce average cost per barrel of oil when used on top candidate wells. There is still a lot of experimentation and technology being developed in this space that will continue to improve returns, and provide a strong market for those companies with appropriate technologies.

This topic has been super hot lately.  Are operators seriously considering refracs?  What service companies are involved?  What basins have historically been refrac’ed?

Our National ReFrac Report is free and our Granular ReFrac Report is $99 per month (or $899 per year) via subscription here.

Included in our Granular Report:

Number of ReFrac’ed Wells by Quarter, Region, Orientation and Trajectory
ReFrac’ed Wells by Year by Top 10 Operator (ALL and HZ wells separately)
ReFrac’ed Wells by Year by Service Company (ALL and HZ wells separately)
Average Proppant Mass by Proppant Type (ALL and HZ wells separately)
ReFrac’ed Wells by Year by Proppant Type (ALL and HZ wells separately)
Proppant Mass Comparison Between Original and Second Frac (ALL and HZ wells separately)
Heat maps for Re’Frac wells for each year
What would you like to see in our reports?  Do you need a custom report?  Are you interested in purchasing a subscription in bulk for your company?
Contact us at if you have questions.
We’ll dig deeper into the Eagle Ford Region ReFracs
Production Correlations
Predictive Analysis
& More

Introducing The Primary Vision US Proppant Mass Index

We are pleased to announce the launch of the Primary Vision US Proppant Mass Index. This index will measure the average proppant mass used in a frac treatment in the United States across all wells.

2011 – Q1 100
2011 – Q2 99
2011 – Q3 100
2011 – Q4 98
2012 – Q1 91
2012 – Q2 89
2012 – Q3 93
2012 – Q4 102
2013 – Q1 103
2013 – Q2 106
2013 – Q3 108
2013 – Q4 117
2014 – Q1 131
2014 – Q2 145
2014 – Q3 158
2014 – Q4 172

Early data for 2015 – Q1 is showing an increase. We will see if that continues.

We can provide a similar index based on our user’s requirements. Example Analysis: horizontal wells only, vertical wells only, directional wells only, by operator, by service company, by region.

Please contact us for more information about these indexes, or if you have any questions about our capabilities, services, or products.

2014 – Q4 Shows 6% Increase In Frac Water Volume Over Previous Quarter. Feb 2015 Primary Vision US Frac Water Index Update

We saw a 6% increase in 2014 – Q4 over 2014 – Q3 in average frac water volumes. It will be interesting to see if this trend continues with recent oil price declines.

Here is the latest update to the Primary Vision US Frac Water Index. You will notice some slight differences from last time we published. We have updated our methodology to give a more accurate representation of average frac water volumes in the region.

Quarter    Index
2011-Q1    100.0
2011-Q2    97.3
2011-Q3    98.4
2011-Q4    93.1
2012-Q1    89.4
2012-Q2    89.5
2012-Q3    87.6
2012-Q4    96.2
2013-Q1    101.5
2013-Q2    103.4
2013-Q3    108.7
2013-Q4    117.1
2014-Q1    129.6
2014-Q2    140.1
2014-Q3    147.9
2014-Q4    156.4

Have questions about our methodology or about Primary Vision’s products and services? Reach out to us here: and one of our advisors will reach back to you.

Introducing the Primary Vision US Frac Water Volume Index

We are launching the Primary Vision Frac Water Index today to show on how the average amount of water used in a frac job has changed over time.

Quarter Index
2011-Q1 100.0
2011-Q2 99.7
2011-Q3 103.0
2011-Q4 95.6
2012-Q1 90.3
2012-Q2 92.6
2012-Q3 87.3
2012-Q4 94.9
2013-Q1 101.3
2013-Q2 100.1
2013-Q3 107.1
2013-Q4 116.6
2014-Q1 137.1
2014-Q2 145.8
2014-Q3 150.4

Going forward this index will be published once per quarter. Available to our subscribers are more detailed indexes broken down by trajectory, region, pressure pumper, and operator. If you are interested in these more detailed indexes please email us.

Please contact us for more information about these indexes, or if you have any questions about our capabilities, services, or products.

Marcellus Shale Market Trends Part 2: Is Average Proppant Mass Still on the Rise?

In our last post, we discussed a variety of factors that have influenced frac activity levels in the Marcellus shale, including continually rising natural gas production levels, basis differentials at regional market hubs relative to Henry Hub natural gas spot prices, and pipeline takeaway constraints. Reduced drilling and completion (D&C) activity by certain operators has been offset by increased activity by others. That said, there is little doubt that D&C activity would be more robust were it not for these factors. We also took a look at some notable acquisitions and divestments in the Appalachian Basin, the most notable of which was Southwestern Energy’s acquisition from Chesapeake Energy of 413,000 net acres and 435 wells with net production in September 2014 of 336 MMcfe.

Today, we delve into well completion designs that have been used in efforts to optimize well performance and what implications it has had for proppant use. In particular, we focus on 16 leading E&Ps active in the Marcellus.

With E&Ps in full-scale well manufacturing mode in the Marcellus, emphasis has shifted to increased operational efficiency to bring down or, at the very least, contain well construction costs. But just as we see across several oily basins, operators targeting both liquids-rich and dry-gas zones of the Marcellus (and Utica) shale have continued to fine-tune well and frac designs to optimize well performance.

In an effort to increase EURs and produce wells to their maximum potential, E&Ps in the Marcellus have been: 1) drilling increasingly longer laterals; 2) improving lateral placement in the reservoir; 3) increasing frac stage counts per well; 4) using shorter stage lengths (SSL) and reduced cluster spacing (RCS) completions (tighter spacing between stages and more perforations or “perfs” per lateral). RCS completions were first adopted in the Marcellus, and operators have been using the technique since early-2012. As Credit Suisse has suggested, RCS completions have become “almost universally adopted in the Marcellus.” Operators are more commonly evaluating well costs and economics based on per-lateral-foot basis.

In April 2012, Range Resources announced that 2 wells using RCS completions produced at twice the initial production rate (IP-rate) as compared to non-RCS wells on the same well pad. In September 2013, Antero Resources commented that using RCS frac designs in 17 liquids-rich Marcellus wells resulted in incremental frac costs that averaged 20% higher than previous designs ($2 million vs. $1.5 million per well). But the operator saw IP-rates increase by 25-35% compared to similar wells in the area. CONSOL Energy commented that when it first used RCS on two wells in early-2012, IP-rate improvements over non-RCS wells were not meaningful. However, the operator observed that after 15 months of production history, these two wells were 20% and 40% above the type curve, respectively.

What is the implication of all of this for proppant? Longer laterals, SSL/RCS completions, and increased stage counts per well all in isolation lead to increased proppant. But the contemporaneous adoption of all of these practices has led to significant increases in average proppant mass pumper per well.

We categorized 16 publicly-traded operators into peer groups as outlined in the table below. The E&Ps have collectively accounted for approximately 75% of frac activity in the Marcellus since 2012.

Notes: XTO Energy operates autonomously as a subsidiary of ExxonMobil and manages US Land upstream operations on behalf of its parent company; E&P categorization reflects that of Raymond James

The proppant mass index presented below uses weighted averages based on the number of wells frac’ed by operators within each peer group. The chart reflects growth of average proppant mass per well using 2011 Q4 as a base of comparison.


Marcellus Average Proppant Mass Index (12Q1-14Q3)

Sources: Primary Vision

The findings are rather staggering. As a collective, average total proppant mass per well is up 2.3x between 2011 Q4 and 2014 Q3. Our analytics reveal that as a collective group, average proppant mass per well has increased at a 32% CAGR between 2012 and 2014.

As this trend has played out, it has had cascading impacts across the upstream supply chain. After a surge of manufacturing capacity expansion during 2012 and 2013 led to an oversupply and falling pricing, frac sand suppliers have seen significant demand growth bring the market back closer to balance over the past ~12 months and have realized . Proppant logistics have been challenging due to chronic shortages of rail cars and truck-trailers as well as intermittently by weather. During 2014, operators have reported delays scheduling frac due to temporary sand shortages. Certain frac services providers have commented that proppant hauling costs essentially doubled overnight during spring 2014 – sand haulers appeared to be colluding by simultaneously charging a per-truck day rate rather than on a per-load basis. Some frac services providers have rushed to lock in long-term supply agreements with sand suppliers.

Primary Vision’s customers leverage our Big Data solutions to gain meaningful insights on the latest market dynamics and act accordingly. By staying ahead of the curve, they can make data-driven tactical and strategic decisions that help increase their bottom line.

Marcellus Shale Market Trends Part 1: Natural Gas Prices & Frac Activity

In today’s post, we discuss natural gas prices, frac activity levels, and some recent acquisitions and divestments in the Marcellus.

Natural gas prices at some market hubs in the Appalcahian Basin have been trading at negative differentials relative to spot prices at the Henry Hub, considered the “New York Stock Exchange of Natural Gas.” This has been driven by a supply glut and take-away pipeline capacity constraints. Natural gas production from the Marcellus shale has increased from approximately 5.0 Bcf/day in January 2012 to roughly 13.6 Bcf/d at present, according to research from EIA’s Natural Gas Weekly Update illustrates.

Marcellus Shale Natural Gas Production (January 2012 - October 2014)

Marcellus Shale Natural Gas Production (January 2012 – October 2014)

Sources: Primary Vision; EIA

Take-away pipeline capacity, especially in Northern Pennsylvania, was unable to keep pace with rising production. The divergence of spot prices can be traced back to mid-2012. Several new interstate and intrastate pipeline projects in different stages of development will deliver natural gas flows to other markets, including the Southeast US. These developments should mitigate the supply backup that has exerted downward pricing pressure. An exception to these regional market dynamics has been the TCO Pool, one of the Appalachian hubs where pricing has kept close parity to Henry Hub prices due its ability to back out deliveries from Gulf Coast sources and its pipeline connections that provide access to several markets.

Marcellus Shale Natural Gas Pipelines and Market Hubs

Natural Gas Prices – Marcellus Hubs (April – October 2014)

Sources: EIA

Facing these challenging dynamics, certain operators have decreased activity levels during 2014 relative to 2012 and/or 2013 levels, including Chesapeake (as further detailed below), XTO/ExxonMobil, EOG Resources, EXCO Resources, and WPX.

On the other hand, certain E&Ps have stepped up or maintained strong frac activity levels, including Southwestern Energy, Antero Resources, EQT, CONSOL Energy, Noble Energy, Talisman, Seneca Resources, and Rex Energy. Indeed, Southwestern Energy recently announced a $5.375 billion agreement with Chesapeake Energy to acquire 413,000 net acres in West Virginia and southwestern Pennsylvania targeting natural gas, natural gas liquids, and crude oil in the Upper Devonian, Marcellus, and Utica. The deal also includes 256 operated and 179 non-operated wells, or 435 total wells, with a net production of 336 MMcfe/d (55% gas, 36% NGL, 9% oil).

Royal Dutch Shell, which has been reshuffling its US Land unconventional oil and gas portfolio in an effort to shore up its balance sheet, has announced a few transactions of late in the Appalachian Basin. Rex Energy acquired 208,000 gross (207,000 net) acres from Shell in a deal announced on August 12, 2014. The $120 million all-cash transaction added significantly to Rex’s asset base in a liquids-rich area covering Armstrong, Beaver, Butler, Lawrence, Mercer and Venango counties in western/southwestern Pennsylvania and Columbiana and Mahoning counties in northeastern Ohio. Two days after details of the transaction with Rex were made public, Shell announced two separate transactions, including a “swap” with Ultra Petroleum. The deal with Ultra involves Shell selling its 100% interest in conventional natural gas assets in the Pinedale Anticline in Wyoming in exchange for 155,000 net acres in the Marcellus and Utica as well as $925 million cash. Interestingly, the Supermajor describes these newly-acquired assets in northcentral Pennsylvania as “highly attractive exploration acreage” rather than clearly-delineated development acreage. The second transaction announced involves Shell selling 100% of its Haynesville shale assets in Louisiana, including associated field facilities and infrastructure, to Vine Oil & Gas LP and its financial sponsor, the Blackstone Group, for $1.2 billion. Shell appears to simultaneously be demonstrating its belief in the long-term value proposition of the Marcellus and Utica, but appears more inclined to focus on dry gas production instead of what may be for the operator less economic wet gas production. Either way, Shell’s well construction costs in the Appalachian Basin are certainly lower than in its recently-divested dry gas Haynesville assets. It will be interesting to see how Shell’s plans and regional natural gas prices will affect its medium- and long-term returns.

Similar to major basins across US Land, many operators active in the Marcellus have managed to bring well costs down due to increased drilling and completion efficiency, driven primarily by the more common practice and larger scale of multi-well pad operations. E&Ps have also managed to exert pricing leverage on vendors, particularly frac services providers that are competing in a market oversupplied with pressure pumping capacity. Recent commodity price weakness has been well-document in the news, but operators such as Occidental Petroleum and oilfield service providers such as Halliburton remain optimistic and report that activity levels recently have not materially changed.

In Part 2 of our analysis on the Marcellus, we will discuss proppant market trends. Stay tuned!

Introduction to the Primary Vision Blog


We have launched this blog in an effort to keep our customers and others interested in Primary Vision up-to-date with our products and services and share insights on market trends. Here you will be able to read about developments in our products, new product announcements, and some analytic initiatives in the works.

As always feel free to reach out if you have any questions or concerns.