Water Water Everywhere - The Permian Water Challenge

Disclaimer: All views expressed in this article are my own and do not reflect the views of any entity what so ever which I have been, am now, or will be affiliated.

Flying over the Permian Basin in West Texas and New Mexico tells a story. The story of one of America's oldest and most productive oilfields. A story etched out visually, in patches of cleared sand, representing frack pads, drill pads, and frack ponds stretching as far as the eye can see - even from 32,000 feet. Areas where drilling and fracking operations are active are marked by huge, multi-million barrel frack ponds, glistening in the desert sunlight rippling through the relentless action of the West Texas wind.

Oilfield roads, many of which are no more than snaking grit and gravel paths twist around the low hills in bright golden streaks connecting it all together - like roman roads, built in the dark. Built on foundations that were formed almost 100 years ago, when the populations of counties in West Texas ran to the hundreds at most, and pioneering oilmen went wildcatting in the desert with little more than a hunch and a bank loan.

Even today, old conventional wells, their pump jacks still nodding in perpetuity produce next to their younger more complex cousins - who penetrate tens of thousands of feet into the strata to the shales beneath. The landscape scarred still by the scoured patches of sand left behind by long since abandoned wells, and long since drained frack ponds - leaving only torn lining, pale top soil and eagerly encroaching grass. The story of what is potentially - due to the unconventional resources found there - one of the largest and most prolific oilfields the world has ever seen.

In fact, if the estimates from the USGS do bear out in reality - the Wolfcamp interval alone may be the 4th largest hydrocarbon source on the planet, bested only by the Ghawar and Safaniya fields in Saudi Arabia (assuming that the perpetually flat reserves numbers posted by Saudi Arabia since 1980s are in fact accurate, about which there is some debate), and the Burgan field in Kuwait.

Some estimates put the original oil in place in the Permian at 106 billion barrels, with 40 billion produced, leaving upwards of 60 billion barrels of oil in the ground, split between residual conventional, and overwhelmingly unconventional resources. If that does turn out to be true - the Permian could well be the second largest oilfield in the world - second only to Ghawar - after factoring in all of its producing formations. A venerable ocean of oil, locked deep within ultra tight shale formations, waiting for desorption to slowly do its work, and release it for its journey to towards the surface. A process that fracking has made near instantaneous.

The Permian basin has a long history, and one that was not uniformly successful. Its story began in earnest when W.H. Abrams drilled a discovery well in 1920 - during the long running Texas exploration boom that was instigated by the discovery of (what was at the time) the most productive well ever drilled in the USA - Spindletop in 1901 - just outside of Beaumont. Unlike Spindletop however - Abrams' well was somewhat lackluster - producing a mere 10 barrels a day, of profoundly sour oil (a feature of the Permian).

It would be another three years before the Texas Oil and Land Company brought in Santa Rita I, on May 28th, 1923 after a brutal (and expensive) 21 months of drilling. It proved to be a 'gusher' and it was this well that prompted wildcatters to begin carving up the Permian in earnest - exploring its entire extent. Names rose and fell, such as Richardson, Murchison, and eventually after wild success in East Texas, Hunt. The conventional fields in the Permian proved to be fruitful - weathering the great depression, proration production limits, and the wild swings in fortunes that early activities in the early Texas Oilfield entailed. It was a near 50 year stretch of booming oil production - turning towns like Midland, Odessa, and Carlsbad into oilfield communities, brimming with expertise, excitement and money. For the record, the Santa Rita I well produced oil for 7 decades after it was drilled.

By the 1980s the narrative had changed. American oil production had 'peaked' from conventional sources, and along with many of the 'boom fields' of the past, the Permian had been all but written off as a 'mature basin'. The 1980s in general were marked by a wave of high profile bankruptcies among the oil and gas giants of historic legend. Enhanced Oil Recovery efforts that had been running since the 60s, with CO2 flooding rising to prevalence in the late 70s had helped slow the decline - but the writing was seemingly on the wall. The USA was running out of oil. That concern would dominate international politics and US foreign policy for the next 20 years.

While many of the conventional plays discovered in the 50s, 60s, and 70s continue to produce to this day, most notably, Wasson, Slaughter and Seminole - the 80s marked the great Permian exodus - as major operators left to seek greener pastures elsewhere - in many cases overseas. The Permian however continued to produce, and those that remained began to venture deeper and deeper into the formation - like modern day Cullens - going 'just a bit deeper' - encountering producing shale intervals as they went.

In the early 2000s, vertical wells began to give way to horizontal wells and hydraulic fracturing, and complex completions became the order of the day. Operators experimented, tested, and re-experimented, and in 2005, the unconventional Permian boom began in earnest - with permits for horizontal wells rising from 12% in 2005 to 40% by 2011. By 2013 44% of the Permian's production came from deep unconventional formations. While the oil and gas narrative was focused on the great gas shales rising to prominence in 2007 and onwards (Haynesville, Marcellus, etc.), the second great Permian boom had begun without anywhere near the press it deserved. US oil production had far from peaked. In fact, its rise was only just beginning.

When the bottom fell out of oil and gas prices in 2015, activity in the Permian slowed dramatically. The Midland area went from feeling like an exciting buzzing hub, to a seemingly cinematic half abandoned ghost town of empty 'man camps', abandoned well infrastructure and empty hotels. Roads to the oilfield were marked by forlorn closed roadside bars/restaurants half way between the town and the desert which once used to service the community of roughnecks and drillers that were constantly being ferried from one pad to another. With oil prices in the $30s - questions arose as to how anyone could break even, or even begin to make money at those prices. Legions of service companies, and some operators could not resist the economic tide and fell to bankruptcy. When prices showed no signs of rising quickly in the short term - mass demobilization began to occur throughout the formation. Rig counts fell from a high of over 550 rigs, to just over 100 in a little over 6 months.

Demobilization costs began to be tallied up, and the operators found something. Water disposal from the multitude of now useless frack ponds (which overwhelmingly relied on SWDs, or in a lot of cases trucking the water for disposal in more receptive states) formed one of the largest costs on their P&Ls. With a fraction of the rigs operating, and a fraction of the frack crews now in the field - the question was asked for the first time out of necessity - 'what do we do with all of this water?' Water was taking a close third behind safety, and production in terms of the operators' priority list.

The Permian however proved resilient as ever. Forward thinking entrepreneurs, that have long found their home in the oil patch in West Texas realized that transportation costs were a key factor in Permian unconventional economics. Great pipelines began to be constructed, despite the downturn, reducing oil transportation costs dramatically. Innovations in fracking wells driven by operators' dedicated research resulted in hugely reduced well completion costs, and suppliers adjusted their profitability expectations to stay in the game, driving down costs of the rentals and frack crews that are the life blood of unconventional oil exploration and production.

By the middle of 2016, while the offshore industry continued to reel - rotary rigs, once again began to find their way to the Permian basin - a trend that continued unabated, to the point that rig deployments and sunk wells outpace the service companies' capabilities to complete them. Upwards of 430 rigs were in operation by the end of 2017. Whispers of break even prices in the $20 range began to reach the ears of investors, and the rush to invest in acreage was visceral. The third great Permian boom had begun, and with the US relaxation on the ban on the exportation of oil - by 2020 it is likely that the US will be the largest exporter of oil in the world, with upwards of 30% of that slated to come from the Permian Basin.

The Permian remains a basin of giants; operators with huge contiguous plays strip mining the shales' oil, intermingled with independents, and still, as has always been true of the basin - smaller operators with big dreams and two to three wells being drilled, hoping to strike it big and flip their interests. The buzz in Midland has returned, with rotary rigs operating mere feet from the highways around the town, and a constant influx of workers, and flights from Houston, Dallas, Ft. Worth and beyond carrying executives, company men and entrepreneurs.

It's scarcely possible to obtain a hotel room in the city most nights, and if one is successful, the hotel bars and restaurants are filled with fortune seekers, and workers, all living the reality of one of the largest upticks in drilling activity in the history of oil and gas. The excitement and buzz in the air is palpable. It's a fantastic time to have a reason to be in West Texas. It is also a time, where in overwhelming numbers, at the bars, restaurants, offices, and drilling pads - water management professionals are present in unprecedented numbers along with the drillers, frackers, managers, and salesmen.

This time around, all operators are keenly managing their water infrastructure. Every major operator somewhere in their annual reports, or their earning calls tout high levels of recycling of produced water, with a goal of 100% recycled. The reason is simple: It is now known that the Permian produces far more water than oil, and that even with ongoing, constant frack operations and a growing number of drilled but uncompleted wells, the Permian is a huge NET producer of water. In fact, some reports indicate that it is such a prolific water producer that it actually outputs 3 - 5 barrels of water for every barrel of oil.

Recycling water for frack operations has become the norm, and questions around ultimate disposal of water if and when frack operations begin to slow are being asked - and in some cases answered. On everyone's mind however is the crux of the issue. Economics. Oil prices remain depressed, and while the operators have proven that there is money to be made - any water recycling operation has to beat low disposal costs at SWDs, still relatively low fresh water costs, and economics typically demand 25 cents a barrel of recycling cost to make it even worth considering en mass.

What 'recycled' water looks like is also subject to extensive debate (often without regard to economic considerations). Operators correctly consider their frack chemistry, their completions strategy, the experience of their frack crews, historic well performance, and what is 'healthy for the formation'. This shopping list of requirements is reasonable geologically and operationally - but as constrained by economics as the Permian is - at times these requirements seem to water companies as wanting to pay for a Fiat Punto, but drive out the lot in a Ferrari F-40 - when what is actually required is a Prius.

Opinions range from fracking with fresh water, to fracking with the formation water - and they vary by operator and frack crew. There are as many opinions on what desirable recycled water looks like as there are operators - but all agree on the cost. If it can't be done for less than a quarter, then it's likely not worth doing, not until the last SWD has over-pressured at least.

Much of this debate is somewhat puzzling on some levels. The frack water, after it is mixed with surfactants, friction reducers, and other frack chemicals, is pumped into the formation, and will immediately encounter that formation, and its water, its dissolved solids, its suspended solids, and its oil. It is difficult to imagine that the frack chemicals encountering those conditions in the frack mixer mere minutes before encountering them down-hole is going to have a material impact on well performance or the performance of the frack chemicals. What is impacted however is pumps, mixers, pipeline infrastructure, etc. which is sensitive to scaling, clogging, and damage when water carrying iron, suspended solids, and oil are run through them. The savviest strategy seems to be to frack with what the water infrastructure can cope with, and the frack chemicals can live with. Water that won't foul the ponds and kill the transportation infrastructure.

Similarly, particle size is an oft debated factor. While low TSS is important, for reasons that will be covered shortly, the overall water management process plays a more important role than recycling in many respects. Even if a frack pond was filled with distilled water, after two weeks, extensive TSS and large particles would be present. West Texas is dusty, and all it will require is one windy day, or a rigorous rain storm, and sand, dust, grit, and organics will have found their way into that infrastructure. Expensive treatment designed to polish down particle sizes for the very limited remaining TSS after an effective treatment regime ahead of the frack pond may not have the desired effect - unless operators want to invest in huge closed tanks rather than the highly mobile and open frack ponds.

The above notwithstanding, there is substantial agreement on certain key criteria. The water must be free of bacteria (particularly APB and SOB), must be clear of iron (which serves as feed stock for bacteria), have low TSS to the point that it can be pipe lined and stored, and must have some level of disinfection residual in it such that it can be fracked with without bacterial regrowth down-hole, which will dampen significantly well production, and risks souring the field. For other dissolved solids - a 'clean brine' is generally moving towards a position whereby it has low TSS, the above criteria are met, and the other dissolved solids are left in solution. This has been a long progression, but is a rational progression.

With the focus on water - water companies have begun to enter the Permian with renewed rigor. Some very well established with broad bases of experience and a huge arsenal of technologies, some appearing almost overnight with a single 'black box' solution. Some even seem to offer the elusive 'magic bullet' that will solve the problem by instantly transmuting solids into nothing, and outputting distilled water - offering pilots, and yet never seemingly having commercial units in the field. Evaporation, RO, BAC, IGF, DAF, and a myriad of complex polishing filtration regimes are being touted as essential (and in some cases they may well be), but examples of them working without issue given the overall water management deficiencies in the basin are relatively rare.

This procession of technology is nothing new to the oilfield. As long as there has been an oilfield, there have been those touting disruptive technologies (some real, some not) that will result in huge savings, allow the drilling of the perfect well, or will save the operators millions. The oil industry's answer to this parade over the years has been a 'show me, don't tell me' mentality, which in the field of water treatment has proven to be a very sensible approach. After all, if it doesn't work in the field, it doesn't work. Economics don't come down to a spread sheet. They come down to what it actually costs.

Two challenges exist in water management however that are inescapable, and they are not going to change no matter the environment, the technology employed, or the marketing around them - and savvy operators are realizing this. The first is the laws of physics; and the second is its closely related cousin - mass balance. Matter simply cannot be created or destroyed, and water has certain innate properties that are not changeable by an approach, a technology, or hope. That is not to say that technology is not absolutely critical in resolving these challenges - because it is - but it has to be the right technology, leveraging a great overall water process.

For example, lets assume there is a recycling facility treating 100,000 barrels per day of produced water, which typically carries 15% TSS and another 15% dissolved solids. Lets assume that there exists a single skid system that will instantly remove all of those solids (and somehow also deal with the oil, iron and bacteria). Instantly, the operator now has 70,000 barrels of solids free water, and 30,000 barrels of solids, assuming that they come out completely dry. In reality, those solids are coming out wet, and so it would be closer to 50,000 barrels of concentrated, wet sludge that has to be disposed of as fast as it is produced. A 100,000 barrel per day produced water problem, has become a 50,000 barrel sludge problem. That alone will kill economics, and see operators asking 'what on earth do I do with all of these solids?' It would seem that a magic bullet may not always be desirable, nor necessary.

Evaporation (in all its forms) which is common in industrial applications which could in theory through distillation massively reduce mass of solids, and output water has its own issues. It's a great technology, but the laws of physics dictate that it takes approximately 1000 BTU to evaporate just 1 pound of water. (The actual number is about 970 BTU - but this is quick math). Each gallon of water contains approximately 8.3 lbs of water. With 42 gallons of water in an oil barrel, that's 348 lbs of water per barrel - requiring 348 thousand BTU per barrel to evaporate (approximately). For 100,000 barrels - that equates to 10.23 million kWh of power - per Google's estimation. Essentially worst case, assuming 8 cent per kWh, it's six figures of power cost per day.

The problem is not the technology - but the scale and the short time line. Fracking takes a lot of water. 30,000 barrels per day on a good day per frack. Wells output a lot of water. This water has to be turned around quickly - such is the pace of fracking. No matter the efficiency of the system - evaporating water takes a tremendous amount of energy, and that power volume is fixed. That power carries a cost. In smaller scale sludge reduction applications, evaporation and similar technologies are valuable, but it will never be magic bullet for large scale recycling operations at low cost. Even if just handling sludge, and offset by disposal cost reductions in terms of volume, the NET power cost runs to the high $10s of thousands per day. While there is talk of selling the bi-products from these approaches to offset cost - most operators don't seem altogether too keen to become salt manufacturers.

Mass balance rears its head again in looking at polishing filtration approaches. Once again, these are proven and fantastic technologies throughout the water industry - however variable feed quality in terms of input water will always prove to be the undoing of filtration which is designed and rated to treat a certain amount of solids.

If the filter is sized for the average load of solids - one nasty slug of water will see the filter in perpetual backflush as it attempts to self clean (or the activated carbon consumed in minutes, rather than days). If it is oversized to meet the worst case possible water, CAPEX and OPEX costs begin to rise precipitously, for a 'just in case' system, that 90% of the time will be running well below its rated capacity. It is a catch 22 that by definition is not going anywhere, and has long been a feature of water treatment. Variable quality feed water will result in huge increases in mechanical or adsorption based filtration regimes costs.

It is worth noting that one industry solved the issues of variable feed quality, and the need to treat sometimes filthy water cheaply decades ago. It was the drinking water industry. That is where innovation in the water space has come from historically, and that is where it is likely to emerge from again. The biggest water challenge faced in the world is not faced in the Permian Basin - but rather faced in the fact that millions go without clean drinking water every day around the world. Two things are understood well in this space. Gravity and time are the friend to effective, and cheap water treatment. Embracing the laws of physics, rather than challenging them is the most cost effective approach.

From this mindset, questions begin to be asked. Why have a DAF? or an IGF? If you have a tank, some oxidants, and some time, solids will tend to settle (and can be aided by weir systems, and other approaches), and oil will tend to float. Why incur the OPEX and the CAPEX for a complex high maintenance system, when simply put, tank space costs less, has near 0 maintenance cost, and will function almost irrespective of the feed quality? Whatever the process, sludge and oil removal costs will remain the same - but maintenance and operation costs will not.

Why use micro-filtration, if the right combination of tanks, chemicals (which can be safely, and at extremely low cost generated on site through the right technology) can drop out 99% of the TSS (and iron, and kill bacteria), and leave only a solid clean brine for frac operations - well above the quality in an already treated frack pond? The 'huge flow rates' in the Permian basin are not on reflection that huge. 100,000 barrels per day can be treated by 40,000 of tank capacity, the right technology, set up correctly with the correct flow regimes, the right addition of safe chemicals, and the right management approach. Just 6 hours of well managed hold and mixing time, combined with the right technology can absolutely transform water.

Everyone agrees that iron needs to be removed from the water as it is the feed stock of bacteria that sour fields, and generate film that blocks the surface area so important to desorption process that is the key unconventional well productivity. It is also universally agreed that disinfecting water before it is used for frack operations is critical to kill those bacteria. These two objectives can also be accomplished by no more than the simple process outlined above. They can be done well (provided the right oxidants are used) within the required economics - and they result in frack fluid that can and is being used successfully to frack very productive wells. Solids and mass balance considerations are of course still present, but solid drop out occurs at manageable rates, reducing solids management costs to a drip, rather than a waterfall.

While complexity has too often been the message - the answer could well be simplicity. Rather than looking for a magic bullet - lessons learned from industries that have been tackling these challenges economically for decades yields proven results - with tens of thousands of installations around the world globally proving the case. Their economics are available to all on their web pages and their published reports - because their customer is the general public. Rather than seeing the laws of physics as an enemy to be tamed, they can be harnessed, used, at extremely low cost, and output effective frack water with minimal effort, and critically minimal expense.

If space or time is at a huge premium, then other approaches become mandated (filtration, etc.) - but time is a function of space for ASTs, and space is not at a premium in the Permian basin. While this may challenge mobility - it is not as huge of an issue as some would imagine. ASTs are moved all the time to new locations. They are on site anyway at gathering stations throughout the basin. They can also be weaponized into effective water treatment mechanisms when combined with the correct technologies to make the most of them combined with the right process - more often than not, without additional infrastructure.

The other challenge faced by the operators is that water management is an end to end activity. It is not a one shot one kill activity - unless one is willing to spend far more than the economics in the Permian allow. From the second produced water exits the wellhead - it must be managed effectively. Most produced water is run through a separator and stored in tanks by the wellhead, which are emptied every day or two. The water management process starts here, not when that water is dumped into a frack pond.

For example, what happens now, for the most part, is that a water transportation company shows up with a truck, and empties those tanks. Those same trucks drive to gathering stations, or frack ponds and offload that water, which finds itself being treated either ahead of or behind the pond. Often times, it is not known with certainty exactly where that water came from, with some transportation companies acting as clearing houses for water.

Unsurprisingly, there tends to be oil in the water - that then requires removal, resulting in at best hold time, at worst (from a cost standpoint) IGF or DAF. The irony being that the Oil is coming from water that has, on average, sat in a tank at the well site for 24 hours. At the time of draining 95%+ of that residual oil would have been sitting on top of the tank due to natural separation. Had only 90% of the tank been drained from the bottom (with the remainder being recirculated through the separator) - most of the oil would have been removed, absent a single treatment regime, just by effective management of the water at inception - obviating the need for complex (and costly) oil removal processes downstream - or at least drastically reducing it.

While the challenge may well be, 'that's a lot to ask of an infrastructure company trucking water' - it is significantly less than it is to ask of a water treatment regime to cope with large slugs of oil one moment, and nothing the next - for economics that in reality require almost no additional oil management in stream. It is unlikely to be reasonable to expect nothing about the water management approach to need to change, and have a treatment system solve all the ills in produced water, many of which are caused by the existing water management approach in the first instance.

This situation is of course complicated by the flow-back water, that comes up with sand, gel, water, frack chemicals, and normally a large measure of oil. This water tends to find its way fed into the same frack ponds as regular produced water - but has had 0 opportunity for settling. Worse, when there is a treatment regime ahead of the pond (which is often the best place to put it) expecting it to be able to cope with produced water economically, but be sized to handle flow-back water and its oil concentrations - is unrealistic within the current economic window.

While there are logical reasons why this takes place - in practice, some level of infrastructure for flow-back water up front could result in huge savings downstream, as every other water treatment skid in stream would not have to deal with the occasionally huge slugs of oil that flow back tends to feed into the process. They would be significantly smaller, significantly more economic, and have significantly lower maintenance costs. The solution to this problem is little more than strategically positioned ASTs, skimmers, (or even DAF) and time, designed to deal with flow back ahead of the pond, but separate from primary treatment streams for the bulk of produced water.

The future challenges faced in the Permian are of course water disposal. While SWDs are common and operating with low pressure for the most part - eventually frack operations will slow as the field begin to mature again. The frack ponds themselves will sit full of water - and given the shortage of water in the area - something must be done with it. Although not a problem the Permian faces today - it is a challenge that it will face in the future. It is here that economics will change, and the industry will have to face the reality that taking that water to agricultural grade, or river disposal grade has dramatically different economics - and that cost is not something that can be avoided indefinitely, only deferred until necessary.

Fortunately for the plucky operators making the Permian their home, there are a number of companies out there that are not selling a magic bullet - but rather a low cost process that can meet any challenges the industry may face now, and in the future, and within the 25 cent window for recycling. At the heart of these solutions is of course, one or two very compelling technologies. These on their own however are not the magic bullet. They become the the magic bullet when combined with processes that leverage the laws of physics, innately available settling and drop out time, the right non-hazardous chemicals, and critically the right end to end water management process.

Picture: A De Nora Water Technologies Powered Recycling Center in the Permian Basin - treating up to 45,000 barrels per day going directly to commercial frack operations.