The celebrated marriage of horizontal drilling and hydraulic fracing has hit a tough patch. To point: We are now producing reservoirs with permeability values as much as two orders of magnitude lower than those developed prior to 2017. These "sub-unconventional" pay zones, if you will, have crossed an abstruse technical and economic threshold, just as investor demands to increase production and cut completion costs raise the collective blood pressure of the entire sector.
Unlike their predecessors, today's ultra-tight reservoirs respond mostly to contact frequency, rather than conductivity. As such, operators focus on extending the effective frac stage length and/or enhancing oil and gas flow within each stage, all the while reducing cycle time on location. Here, flow uniformity to increase the drainage of every stage must be the central component of any frac design. That said, what we've found in our practice is that designing a frac program around the use of largely unsung biodegradable frac diverters is unequivocally the single most effective way to deliver the higher returns investors demand. In fact, I know of no other tool that singularly delivers higher reservoir productivity, while lowering completion costs and risks.
Simply put, frac diverters plug perforations and near-wellbore heel clusters, which greedily consume more than their share of frac fluid, and re-direct flow to mid-interval and outer-toe fractures that inherently receive an inordinately lower volume of the proppant delivery medium. By increasing the effective stage length, reducing spacing between the individual clusters, and generating uniform flow you increase both production and estimated ultimate recoveries (EUR), while simultaneously reducing the completions cycle time and associated costs, which I'll touch on in a moment. But first, a bit of perspective is in order.
During the shale explosion of 2004-2009, we had cracked the code and began producing full bore from what had been rightly described as "yesterday's dry holes," meaning zones once deemed too impermeable to be regarded as anything other than sub-par assets. While those reservoirs relied on high degrees of conductivity and infrequent contact to maximize production, their contemporaries feature the shallow migration of hydrocarbons into ultra-impermeable rocks that are best defined as "contact type" reservoirs.
Whereas the "conductivity-type" rocks of yesteryear generally required costly ceramic and other high-yield proppant, the new-age emphasis on contact and frequency means a low to moderately conductive, and less expensive, sand proppant sufficiently generates economic production and higher EUR. At the same time, when you can extend the effective stage length, you not only reduce the number of friction-inducing cycles that notoriously stress couplings and can eventually deteriorate into parted casing, but also require fewer plugs. In the Delaware Basin for instance, the price tag for plugs alone range from $3,900 to $6,900/set.
By far, however, reducing the completions time represents the single most influential cost saving component. Back to the Delaware Basin, we find that using a fixed-cost pricing model of a mid-sized service company, where time on location and materials are priced separately, a 12-hour reduction in time would equally result in a roughly 12% spread cost reduction. Also keep in mind that as the name implies, biodegradable diverters degrade into benign and water soluble lactic acid, which simplifies removal during the wellbore clean-up process.
All-in-all, from our experience the less time on location and the lower associated material costs have resulted in documented cost savings of up to 28%. More importantly, field recaps have shown across-the-lateral flow uniformity generally boosting production rates anywhere from 18% to 40%, while we've also seen EUR values 12% to 40% higher.
At the end of the day, a case undeniably can be made that from a mathematical perspective, biodegradable diverters are the only tools available that can both lower the denominator (costs) and increase the numerator (production yield) in the value-return on investment equation of unconventional wells.
For more details on how I arrived at this conclusion, I encourage you to check out "Unsung tools for boosting profitability of unconventional wells" by Lyle V. Lehman, et al, in the July 2019 issue of Hart's E&P magazine.
While attending a DUG conference several years ago, I heard someone say during a Q&A session that the best way to get 10 good wells from an unconventional play is to complete 100 wells. To me, that remark smacked of poor planning and settling for a "whatever-comes-your-way" rationale. Unfortunately, that thinking can still be found in the unconventional community, particularly when it comes to determining optimal fracture spacing.
The near-universal strategy for today's unconventional completions is to load up more and more proppant per lateral foot and narrow the fracture spacing to increase pay zone contact frequency. The idea is that shortening the space between fractures compensates for lower-than-expected source rock permeability, thereby heading off the rapid drop in production that comes when reservoir fluids struggle to flow through the rock fabric.
All this is well and good, but what exactly constitutes optimal fracture spacing? Frankly, the only way to answer that question with any semblance of precision is to take the time and energy to develop a thorough understanding of the characteristics of your specific reservoirs, together with looking at the reservoir-specific economic considerations that will promote higher production and, with it, higher returns on investment. For this approach to be effective, you must first get a firm handle on the permeability distribution of the targeted pay zones and design your frac program accordingly.
In our practice, we have demonstrated that taking an engineered approach to designing the fracture-spacing scheme can pay tremendous dividends, including considerable increases in reservoir drainage. As a case-in-point, our experience in modeling Wolfcamp wells in the Delaware Basin has resulted in fracture spacing progressively shrinking from 120 ft to 40 ft, with the prospect of 25-ft fracture spacing lurking around the corner. While steadily narrowing the fracture spacing, our engineered approach has helped deliver a roughly 24% increase in initial production rates, with an estimated 8% improvement in estimated ultimate recoveries (EUR), as well as 90-, 120- and 180-day net gains in barrels of oil equivalent (boe) recovered.
Without digging too deeply into the weeds here, our methodology is built around the mostly overlooked art of using frac data for net pressure-matching fracture stimulations and the building of a mechanical earth model that distinctly represents your specific reservoir. We have also found that the construction of a correlation database of near-wellbore and stage-centric data is an extremely useful tool. Once the database is assembled and the predictive model refined, the data is then transferred into the reservoir model that includes every critical element, such as stress, permeability, reservoir pressures and the like, extending to those with less relevance that, nonetheless, could impact your reservoir, and ultimately, economic performance.
Through this exercise, you may discover three or more factors that drive your project's economics. Let's say, for example, that the model shows reservoir permeability, completion contact percentage, frac fluid volume and proppant conductivity are the predominate technical enablers for high reservoir performance. In this scenario, your best bet is to shell out for premium, high-conductivity proppant. On the other hand, if the analysis indicates reservoir permeability on a new well is actually 50% of the original value, the model would advise that contact must be increased 70% with a reduction in proppant conductivity. In that case, you only need a lower-quality and less expensive proppant that simply scours and potentially bridges the fractures. And as we all know, in today's unconventional economic environment, the marching orders from the investment community can truly be summed up in "get more and spend less."
At the end of the day, accepting the results of a new and fully calibrated model can only come with time and really needs a champion to realize that the answers make sense, the model is good (or bad) and, when all is said and done, fracture spacing is being optimized.
To learn a bit more on Frac Diagnostics' methodology for optimizing fracture spacing, check out the full article "Can 'too close' be ill-advised in fracture spacing?" published in the November, 2018 issue of worldoil.com. (Subscribing to the publication may be required in order to view.)
Click the arrow below to listen to the Deep Dive Podcast featuring Lyle Lehman discussing the article in more depth.
One of my best and favorite clients recently accepted an offer to sell their properties in the Delaware basin. Of course, in today's market, these decisions occur on a weekly basis. In this case, while happy they get to reap the fruits of years of labor and sacrifice, I'm also saddened because I'll miss the interaction, until if or when they decide to re-group and start over.
In consulting circles, handling a client's goals while tempering them with the realities of their particular situations, is known as 'client management'. As a consultant, I specialize in client management and the more experienced I get (note grey hair) the easier it becomes. However, developing this management skill certainly was anything but easy in the beginning.
Take this client for example. They were developing a portfolio of properties in the Bone Springs - Wolfcamp, several of the shallower Canyon reservoirs, along with some other reservoirs they were considering. They basically were flying under the radar, yet managed to be fairly successful in picking up prospective properties. At first, I was helping them establish better practices for completing these formations and afterwards helping improve these practices for better well results. Keep in mind that when we began this work in 2012, some of the targeted reservoirs clearly represented the most extreme definition of 'unconventional'. In other words, at that time you would not regard these reservoirs as viable, but that's the space in which we were playing.
Working together, we bridged several milestones over the years:
We developed the case against 100-mesh sand. We discovered 40/70 proppant was just as capable of providing bridging and diverting than 100-mesh. The service companies definitely applauded the switch as they were concerned about the erosional issues 100- mesh sand would have on their equipment.
We established the best method of perforating, and it was not limited entry. The actual perforating scheme we developed was a basic 8 shots per cluster. Why not limited entry? Simply put, perforation geometry, as discussed in SPE paper 18273, eliminates the benefits of limited entry. If a perforation cannot open, simply relying on excessive pressure to open the perf job is a false expectation. While the paper did not express this fact in this manner, that's the bottom line.
We developed cluster spacing theory, then tossed that out and redeveloped a better theory. One of the best criteria for a satisfying client relationship is when they join you in refusing to remain fixed to the 'status quo', and actually try to generate some innovation to meet their goals. We did this with cluster spacing. 'Back in the day' we were limiting ourselves to 3 clusters per stage, but as we drew the cluster spacing tighter, we quickly figured out that adding stages to cover the gross lateral distance would require more time, and as we all know, more time on location not only equals more costs, but more risks of events like parting casing. So, we quickly went to 4 clusters per stage and, owing to analysis of the treating data, learned this was basically effective. Yes, we had some cases where the perforation loss was equal to a cluster (and in some cases 2 clusters, meaning that of the 32 holes perforated, we could only measure 16 open perfs), but the overall impact was negligible.
We employed drilling data into the cluster placement and benefited by improving perforation efficiency. This was a very efficient step forward and, sad to say, we employed it on the most recent — and now last — well in their now-sold portfolio. The huge difference is that we went from 45 to 61% perforation efficiency to more than 90% by simply allowing a third-party consulting company to use the drilling data to generate a stress along the lateral (there are 2 providers of this data and it is captured on 6-in. intervals). This enabled us to see the benefit of moving a cluster 5 to 10 ft or so to level-off the stress between the clusters and allow more clusters to open on the initial breakdown. Production results are better and the cost for remediating this issue was recovered within hours.
These, and other milestones, exemplify the mutual benefits of a close client-consultant collaboration. But, getting back to my personal feelings of missing the interaction and working relationship with this client, I'm reminded of what guitarist Bernie Leadon said 6 months after he left the Eagles rock band. He justified leaving the widely popular group he helped found by saying he was tired of the touring and never liked the pressure of big money-making bands. He'd simply wanted to make music and be happy. Sometime after his exit, Bernie attended an Eagles concert where he first saw his replacement, Joe Walsh. While happy for Joe, Bernie said upon watching the on-stage repartee he was once a part of, he came to realize that being enmeshed in an expert team actually meant more to him than he'd realized.
For sure, being a part of the synergy that accomplishes goals is addicting, exhilarating, and requires constant practice. That, my friends, is precisely why we consult.
Listening to several of my Delaware Basin clients speak the other day about the news of several sand mines opening brought mixed feelings. I fear the good news may not be as affordable as everyone hopes. From an article in the industries periodical Aggregates Manager, published in January of this year, by the end of 2018 there could be the capacity to produce 14.3 to 20 million tons of frac sand per year from these mines... and that's only the beginning. That volume represents up to 50% of the total Permian Basin proppant market this year alone and with the announcement of additional plants coming on board, it is easily feasible to predict that the entire Permian market will be locally sourced. Plus, some proppants will be available for other markets which suffer from travel expense of Northern White Sand.
Good News. Obviously, the best news is that the transportation costs alone will be reduced 40%. Because hydraulic fracturing has become a leading portion of the AFE for well costs (and that is absolutely nothing to take lightly). This will have a major impact on reducing well costs. Total well costs will go down. For this reason, one of my clients — who clearly subscribes to the 'conduct v. conductivity theory of completion' — fears that his company will be forced to use the inferior sands solely due to cost reduction. This cost reduction alone could mean that a package of 7 or 8 wells, with reduced cost due to proppants, may yield enough funds to drill an additional well. That is a very strong argument for using these sands.
Bad News. Simply stated, this is poorer product replacement. Current reports are that most of the sand in the Monahans-Kermit area will produce 60 to 70% 100 Mesh and smaller than 100 Mesh-category of proppants. The remaining will be mostly API 40/70 mesh with very little coarse sand. In Frac Diagnostic's practice, and if you have dug through our website you will know this, we view some source-rock reservoirs as being better completed using conductivity and the other reservoirs benefiting principally from frequent contact. In the contact types, what we mean are performing fracs on a very frequent basis, something like every 20-60 ft. of measured depth along the wellbore. These reservoirs will benefit in the mid-term (we seldom see any long-term production when it comes to sub-microdarcy rock) from frequent contact and the 40/70 sand. Logically, the reservoirs that respond to conductivity placement will not benefit from fine-grained proppants.
What Does this Mean? Let's get a few dialogue points into the equation:
 Source Publication: Aggregates Manager; 3 Frac Sand Mines Open in West Texas, 23 More in the Works:
aggman.com article link
 This is due to horizontal drilling allowing a wellbore to be placed in the pay zone for 0000's of feet, which makes it possible to place 12,000,000 lb. or more of proppant in a single well, thus increasing the completion costs.
 Source Publication: Aggregates Manager; Construction of Frac Sand Mines in Texas Threatens Livelihood of Wisconsin Mines:
aggman.com article link
 This is what used to be known as 'Unconventional Reservoirs'. But seriously folks, when a reservoir requires fracing to be economical to produce, that is unconventional. The real paradigm shift occurred when the industry decided to complete wells in the hydrocarbon source, rather than the hydrocarbon target formations.
 An oddity in the use of finer materials such as 40/70 sand is that the higher number of particles tends to relieve the stress distribution in the proppant pack. Meaning that coarser sands crush at a lower stress than finer sands.
A short time ago, my wife Brenda and I were chasing one of our passions of visiting all of the great wine producing regions of the world as we are collectors and have put some serious money and study into it. This vacation we chose Margaret River Western Australia (WA) as Brenda is a Cabernet fan, and they certainly produce great wines there. QANTAS offers many wines from Margaret River on their flights, and since I know QANTAS' wine director, that was all the reference that I needed.
After learning to drive from the right side of the car on the left side of the road, we managed to visit the little town of Margaret River and were in a very nice store examining local olive oils and the like. The store owner heard us speak and knew that we were 'not from around there" so she engaged us in talk. Soon the question of 'What do you do?' came up, and after I told her that I am a fracturing specialist, she advised me that she was okay with it, but that a very vocal minority of locals had helped to support a moratorium on fracing in Western Australia. Of course, I was not aware of any active oilfield work south of Perth — I have performed some analysis of stimulation data from wells north of Perth, therefore had some direct knowledge of WA — so I assured her that she had little to worry about. Then the story got more interesting.
A few days later, Brenda caught a glimpse of this sign (image right) at a very popular pub near Dunsborough, WA.
(My second warning, notice the 'k' in fracing. It's a clear signal that the people who created the poster are amongst those who don't know what fracing is to spell it correctly.)
The next morning on 20 September 2017, the Prime Minister, the Honorable Malcolm Turnbull, held a press conference in Brisbane announcing that he was taking actions to keep gas from leaving Eastern Australia as a gas shortfall was occurring, raising prices which further raises the price of electricity which effects all consumers — and being a Labor Party member — Turnbull cited the struggle that the high cost of electricity has on retired people and the poor (notice: class envy works 'down under' too). Turnbull further mentioned that he was pursuing active investments in renewables and the like, being the Labor Leader that he is.
But I started wondering what this was all about. I knew that Australia had plans to become the #1 gas exporter, so I assumed that they would employ whatever technology was needed to fill their liquid natural gas (NGL) plants and meet their contracts. They have employed fracing in the Cooper Basin of Queensland and South Australia, and that basin in particular is world-renowned as being a very difficult one to complete wells economically, and only through fracing can it be done.
About that time, I received a call from a business acquaintance who is trying to promote a non-liquid based fracing alternative. He told me that his potential client advised him to seek business in Australia because most of the country had placed a mortarium on fracing. Purely by coincidence and Brenda's love of Cabernet, I found myself on one of the political battle lines involving fracing.
How did this happen?
If you are having trouble keeping up, the score so far is that the main three Australian energy providers — Origin, Santos and Shell — along with a lot of other small coal bed methane operators (they call it Coal Seam Methane for reasons that I don't understand) had pledged gas to fill the new NGL plants so they can make Australia the #1 gas exporter. This means jobs, stronger economy and more ability to attract good people to the land of Vegemite and Kangaroos. But somehow, these goals cannot be met while also having enough gas to generate cheap electricity for the citizens of Australia. My interpretation is that the profits from contracts to provide higher-priced gas for export outweighed the cheap domestic gas and there is a supply shortage in an area that is rich in supplies, or so it seems. How did this happen? What was the first step in this process of failure?
Simply stated, an American — Josh Fox and his movies: Gasland I and Gasland II.
Gasland I premiered in 2010 and in a short time was the talk of the town. Over time, most if not all of Josh Fox's allegations have been proven false and I won't go into that fight as many have corrected him. Speaking of QANTAS, the airline showed Mr. Fox's films on their domestic flights all over Australia which, if you never watched the Manchurian Candidate, you need to know that if exposed to any bit of information often enough, many people will begin to believe it. Despite claims that are proven false and in some cases, defy the laws of physics and time for that matter, many people, including the wine growing citizens of beautiful Margaret River, believe Fox.
Thinking that money drives everything, I wondered what motivated Mr. Fox to tell lies and promote his films. Good guessing on my part. If you look into the financial backing of the Gasland movies and then the $$ offered to allow QANTAS to promote the movie on their flights, you eventually come to at least one unique source: the Soros family.
Let's follow the money to find out. Fox reportedly received $750,000 from HBO Documentary Films to pursue Gasland Part II. No one can verify how much money changed hands or who exactly it went to however. This is because Fox's non-profit production company, Sweet Jane Productions, Inc., has yet to file an IRS Form 990 for any period since June 30, 2010. He uses this non-profit corporation as a vehicle to collect government grants and support from the likes of the Rockefeller Foundation ($50,000 for an "interactive drama exploring theater as immersive and educational"). He has received at least $275,000 from Park Foundation for promoting his anti-gas films and a proposed Gasland Part III. Whether his charity facade was used to collect HBO money for Gasland Part II is unclear.
What is clear is that the President of HBO Documentary Films, Sheila Nevins, has been closely involved with the Soros family through another non-profit corporation called the Creative Capital Foundation, which has been another source of funding for International WOW, Fox's d/b/a for Sweet Jane Productions. International WOW received $50,788 from Creative Capital in the last fiscal year for infrastructure support and Sheila Nevins was an early board member of that organization, along with Jeff Soros, the film producer-nephew of George Soros, the insider trader and funder of so many leftist causes and other nefarious enterprises (e.g., almost bringing about the economic collapse of the United Kingdom).
The nephew Soros has a film company and apparently has put out one film after more than a decade. It's apparently quite good but, fittingly, is called 'A Small Act' and, of course, was put out by HBO Documentary Films. Prior to that film in 2010 he appears to have spent most of his time writing screenplays that didn't get produced and learning how to give his money away. Meanwhile, his uncle George and cousin Jonathan have been giving Andrew Cuomo $750,000 to play Hamlet on the Hudson, Lady Macbeth and any number of other tragic Shakespearean characters that come to mind as he puts upstate New York through a living hell. No doubt George likes the idea of keeping New York out of the fracing game — it probably increases the value of his Petrobras investment. Although Soros is the kind of guy who plays both sides in order to win.
The US anti-frac efforts miss their target
In 2009, Barack Obama took office as President of the United States. With this event, the oil and gas industry felt a shift in energy policy, which might be best characterized by former EPA Administrator Al Armendariz's 'crucify them' comment about the industry in 2010. In October 2009, the US House of Representatives took steps towards initiating the EPA Hydraulic Fracturing Study. This latter effort was described as a 'peep show' by the late Dr. Michael Economides in May 2011 and was viewed as one of several attacks on the industry. During Obama's first term, US Senators Henry Waxman and Ed Markey and US Representative Diana Degette also led several inquiries into hydraulic fracturing. The January 2010 release of the movie Gasland I and the April 2010 blowout in BP's Macando well may have fanned the flames fueling anti-industry sentiment during this time.
From a historical perspective, the EPA Hydraulic Fracturing Study seemed to be the aftermath of disputes starting in the 1990's regarding regulation of producing wells drilled in coalbed methane (CBM) reservoirs. In Alabama, environmentalists noted how some CBM wells are fraced near or within geologic formations classified as Underground Sources of Drinking Water (USDW). With this, environmentalists felt that the CBM wells should be treated as Class II injection wells regulated under the EPA Underground Injection Control (UIC) Program. In 1997, the Eleventh Circuit Court of Appeals sided with argument of environmentalists, which sets the stage for later events. First and foremost, the State of Alabama revised its UIC program to regulate the fracturing of coalbeds. In June 2004, the EPA published a study of fracturing CBM wells in the United States. In 2005, the study's conclusion that fracturing in CBM "poses little or no threat to USDWs" would be used to justify legislation involving fracturing. During this time, environmentalists criticized the CBM study based on potential conflicts of interest. Critics also touted a 2003 memorandum of agreement eliminating the use of diesel in CBM fracturing as proof that there was a problem. In the years leading up to the release of Gasland, much of this sentiment appeared to be unresolved.
Figure 1: 2000-2010 United States Rig Count (Source: Baker-Hughes) and US Natural Gas Wellhead Price (Source: EIA)
From the start of 2002 to the end of 2008, the industry experienced a steady increase in activity (Figure 1). Much of this pace was driven by commodity prices. During this timeframe, oil and gas operators began finding success exploring deep, unconventional reservoirs (shales). Operators also gained efficiencies from using horizontal drilling and following up with completion technologies such as hydraulic fracturing. Even though unconventional reservoirs are typically separated from USDWs by thousands of feet of rock, the level of activity surely caught the attention of environmentalists and other industry critics. Furthermore, certain entities across the globe most likely viewed hydraulic fracturing as a threat since its application in the US increased the supply of oil and gas, and therefore impacted commodity prices.
And the latest news came on September 29 that Russia could possibly be behind anti-fracing propaganda on Facebook and Twitter... (calling the Manchurian Candidate).
Where do we go from here?
All and all, one needs to understand a basic fact that drives America's acceptance of fracing as a completion tool: Most Mineral rights in America are owned by individuals, not the government. To illustrate my point, if you take the time to watch Frackman the Movie, the opening remarks convey that Dave Pratzky of Queensland Australia (the subject of the movie) says that he was not in control, nor could he benefit from the coal seam gas production under his land, whereas most of the land owners in the Eagle Ford and the Permian basins do benefit. Pratsky's motivation to stop the process is clear, and I for one cannot fault him for that. No one wants to watch people freely coming and going on their land and disturbing their environment.
As I have said, it all gets back to money and I feel that as long as we frac folks continue to take the precautions to make the practice as safe as we can and are cognoscente that people such as Dave Pratzky and Josh Fox are making money off our potential carelessness, real or imagined, that everything will be OK — at least on my watch.
Brian Dzubin of Frac Diagnostics, LLC contributed much of the background content in this piece.
The Australian PM, Past and Present Blame Game:
Assuring Cheap Gas for Australia:
Josh Fox Exposed, Part 1 (of many, but a great moment in Journalism, live!):
An honest crusader against exploitation of his land:
Gasland Part II Funding, follow the Soros Money:
An honest crusader against exploitation of his land:
Coalbed or Seam, you pick:
Russia buys anti-frac ads for Facebook and Twitter:
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