US net crude oil imports are dropping and will continue to drop even more. The idea of achieving US energy security will get stronger over the years, and it is being driven by hydraulic fracturing, shale gas, and tight oil, said John Martin, founder of JP Martin Energy Strategy LLC.

The number of drilling rigs, frac crews, and other infrastructure doesn’t exist elsewhere in the world. The shale revolution won’t happen tomorrow, but it will happen, Martin emphasized in a “Hydraulic Fracturing 101” webinar produced by Energy Seminars International in January.

“The technology investment in hydraulic fracturing and horizontal wells is paying off,” he said. “It is amazing to watch the transformation of the industry where it is getting into these tight rocks and producing that hydrocarbon at a cost that looks like the 1970s.”

In some ways, the technology of hydraulic fracturing is just beginning. The industry is moving from using brute force along the length of a lateral to finding ways to finesse the oil and gas out of the formations with optimum placement of stages and clusters.

“I would say that the efficiency successes and the cost efficiencies that we’ve seen on the drilling side are lagging somewhat on the completion side of our business,” said Rob Fulks, director of shale resource projects and pressure pumping services for Weatherford. “There is so much pressure on operators to reduce their completion costs, which seems to be paramount right now. The drilling side has done such a great job in getting the days to depth reduced that it’s hard to keep up with the efficiencies on the completion side that they’re seeing on the drilling side.”

Jeff Meisenhelder, vice president, unconventional resources, Schlumberger, noted that the recovery factor for the liquid phase is about 8% to 12%. “It would be a giant step-change in the industry if we doubled the recovery factor. If a good well in the Eagle Ford produces 500,000 bbl estimated ultimate recovery (EUR), then a well that produces 1 MMbbl EUR would be a new game economically.” Some of these game changers can be found in unlikely places, according to John Ely, founder of Ely and Associates.

“We’re having a lot of success not only in source rock shales and stacked sand-shale sequences but also in carbonate reservoirs across the country, which are extremely tight formations that the industry has overlooked,” Ely said. “We’re making 150 b/d to 300 b/d wells. These are vertical wells with very large slickwater fractures down 7-in. casing, which makes it easy to pump.

“One of the interesting things is that some of the operators are finding that vertical wells with proper frac designs are more economical than horizontals. At the same time we are also achieving extraordinary results with all types of fractured reservoirs using fracture location technology to bypass the statistical lateral stage length and number-of-clusters guessing game, which dominate our industry,” he added.

Statoil US onshore is out to create the “perfect well” in drilling, followed by completions (including hydraulic fracturing), rig moves, and completion operations. The perfect well will always be another step-change beyond best demonstrated performance (BDP), explained Kevin O’Donnell, head of operations support for Statoil US onshore.

“BDP has a basis of reality,” he said. “It has been accomplished in the field. We have seen cases where what we thought was perfect turned out two years later to be less than what we thought was perfect.”

As Martin noted, drilling costs and completion times are dropping. Initial production (IP) and EURs are better. “This is what is going to cause a global revolution,” he said. “It has certainly caused a North American revolution.”

But how much farther can the oil industry go in improving hydraulic fracturing, completion efficiency, and production effectiveness? E&P interviewed experts in the field about what direction they see the industry and technology heading.

Well productivity

How do companies go about increasing well productivity? “There are several trends that we’re noticing,” Fulks said. “I guess one of the bigger ones is led by Laredo, UG, Continental Resources, and some other companies. There’s a tendency toward super fracs. UG in particular has shown that by increasing proppant loading, well IP rates can be vastly affected positively.”

As an example, Fulks said Weatherford has a client that consistently stimulates 3,049-m (10,000-ft) laterals with 32 stages in the Bakken. That company is completing those 32 stages with a total of 2.4 MM lbs of proppant. In the same area, EOG is using 7.4 MM lbs to 10 MM lbs and in some cases north of 12 MM lbs of proppant in the same type well, and its IP rates are dramatically different.

Ely said his company is watching very closely recent high-water volume, high-sand volume treatments with slick water, where the only proppant utilized was 100 mesh and 200 mesh sand. These types of treatments have been conducted in oil-producing reservoirs at depths greater than 2,439 m (8,000 ft) and as deep as 4,651 m (12,000 ft).

“The wells are performing quite well. Two things are unique for this type of treatment. The first is extremely high volume of fluid, and second is the exclusive use of

small proppant in oil reservoirs. The industry or the majority of the industry has seen and accepted small proppant in gas reservoirs but has proclaimed the need for bigger sand for oil. That is simply not the case for the low-matrix permeability reservoir where complex fractures are created.”

All the things the industry was taught in fracturing conventional wells – using crosslinked gel, packing the fracture with sand, and pounds per square foot – don’t work in naturally fractured reservoirs, he explained. Legendary oil man George Mitchell proved that what is needed is high-rate, high-volume slick water.

The industry is now pumping a lot of non-American Petroleum Institute sand.

“We didn’t have the volumes to pump all Ottawa sand or all ceramics in our early frac treatments in the deeper shales,” Ely said. “What we’ve found – not out of science but experience – is that smaller sands work in deep shales like the Eagle Ford and Haynesville. One of the biggest operators in the Haynesville hasn’t pumped anything but small sand for the last three or four years, and that is at 3,658 m (12,000 ft).

“Truly the enhanced productivity is due to massive surface area. You can get much larger volumetrics with just water, friction reducer, and small proppant. The small proppant is transported farther, and it is smaller and able to penetrate into smaller fractures,” he emphasized. He pointed to a 600-well study in the Eagle Ford that showed volume of fluid, not sand, was the No. 1 factor in hydrocarbon recovery. It may be that both volume and sand are needed, he said. With the emphasis on smaller sand for slickwater fracs, operators are faced with having enough proppant on location, Fulks said. “When we talk about increased proppant loading, we’re seeing demand for proppant way, way greater. That means usage is going up tremendously, just as we thought,” he said. “Having onsite storage sand, particularly if you’re going to do zippers or multiple wells on a pad, is extremely important to cut down on the truck traffic.” Meisenhelder stated, “Arranging perforating clusters into stages with similar initiation pressures has proven very effective in improving IP and making every fracture count, but you need data along the lateral to make it possible. New

tools and conveyance technologies have brought the cost and risk of gaining this data down to an acceptable level. This technique is rapidly gaining acceptance.”

Following natural fractures

Getting results from natural fracturing is very basic, according to Ely.

“What works is surface area and volumes,” he said. “Not many things are cheaper than water. Efficiency when you switch over to something like nitrogen or carbon dioxide goes down even in these very tight reservoirs, and the cost goes up.”

There are, however, plenty of applications where nitrogen and carbon dioxide are needed due to logistics with water supply or extreme underpressure.

Typically these are reservoirs with naturally fractured, low-permeability rocks.

“If you’re talking about low-permeability rock, the only thing that is going to work is surface area that is propped open and has conductive flow paths,” Ely explained. “With slick water, we’re getting very complex, spider-web type fracture systems, and we’re making better wells with smaller sand. That’s the big step-change in our industry.”

One way to see what is happening in the reservoir is to use formation microimaging logs. “If you can do that, then you can cheat and actually perforate into the fracture systems,” he added. “Then we’ll quit guessing and experimenting with the number of clusters and actually perforate where we should.”

One problem with microimaging logs is that the technology is not compatible with oil-based mud and a lot of the shale is drilled with that type of mud.

“The oil-based technology is not such that we can selectively perforate the brittle zone,” Ely said. “There are service companies promising that they can get microimaging logs with oil-based mud that will allow us to quantify fracture presence. An oil-based microimaging system that can be run in LWD would be a tremendous boost in our ability to effectively stimulate naturally fractured reservoirs.”

Microimaging systems work very well in water-based drilling muds. “That technology has been extensively used but not widely advertised,” Ely said. “Lateral microimaging greatly enhanced the development of the northern Barnett shale.”

Slick water vs. crosslinked gels

With the added volume of proppant in the fractures, the debate over which fluid is best for placement – either slick water or crosslinked gels – continues unabated.

“It’s a very interesting time in our industry where we’re just about as bad as the Democrats and Republicans. We’ve got the slickwater people and the gel people. I think we know who is winning,” Ely said as he laughed. “About 80% of the jobs, probably higher, are in fact slick water.”

Conversely, Meisenhelder indicates that statistics show hybrid jobs, where fracs are initiated with slick water but

followed by cross-linked gel, are increasing, while the overall use of slick water is decreasing. The hybrid technique takes advantage of the properties of slick water but also capitalizes on the better proppant transport capabilities of gels. “Advanced fracture modeling tools that take into account both rock properties and fabric are enabling us to predict the effects of changing fluid designs on fracture complexity, proppant distribution, and conductivity. We can now efficiently optimize job designs that are fit for the reservoir you have rather than the one next door.”

Ely thinks hybrid fracs are slick water fracs. “I think what’s confusing people is that the majority of jobs that are crosslinked have no stability and are basically water after a short period of time,” he said. As a hydraulic fracturing consultant, his company did 27,000 frac stages in 2012.

“What we believe is that the thin fluids in high-volume water fracs are giving complex fractures, and that’s why we’re having so much success in the shales,” he said.

But Ely also recognizes the need for gels. “We can testify that in the Haynesville if you don’t run viscous fluid, you can’t place sand due to severe tortuosity, and that gets complicated,” he said. “But once you remove tortuosity in a lateral you can pump anything you want to. What we’re finding is that we get better results with smaller proppant, which is counterintuitive for fracturing. We’re finding across the country and the world that slick water is working virtually everywhere.

“For anything that is naturally fractured, whether it is shale or coal or carbonates in West Texas, what’s really working is slick water, and it’s the primary reason for the ongoing gas bubble and our huge increase in oil productivity,” he added. “Many of the larger operators in Eagle Ford have switched from hybrids back to slick water.”

Statoil’s ‘perfect well’

Statoil has some deliberate improvement initiatives. Rather than evolving over time – a learning curve – the company has initiatives to accelerate the learning curve in this phase of its evolution, which is called the “perfect well.”

“The perfect well is based on an old Japanese manufacturing process called SMED, which stands for single minute exchange of die,” O’Donnell said. In manufacturing, a die is a device used to shape, finish, or impress an object. “It’s a very simple process for breaking down what you do in a lot of detail, questioning why and how you do it, and building back up from the bottom and getting a different and better result.”

The process begins with understanding what is being done today in detail. Next, there is a discussion around the table about what can be eliminated. Statoil began with its drilling operations and will progress later into completions. The ideal group to discuss processes consists of about a dozen people intimately familiar with the operation – drilling engineers, engineering supervisors, drilling managers, and superintendents along with the drilling contractor on the rig. Over a three-day period in August 2013, Statoil facilitated the workshop, asking what can be eliminated.

“What we find out from our teams is that what we thought are requirements really aren’t and that we can actually take them out of the process to get the same or better results by eliminating certain steps,” he explained.

The group then looks for steps that can be moved off the critical path. “In the case of a drilling operation that runs about [US] $100,000 a day, anything that we can take off the critical path and do before, parallel, or after will take that cost away, which will shorten our overall cycle time,” he said. “Next we look at what we can shorten through technology, automation, or better processes. When we implement the changes, we’ve saved a whole bunch of time in our cycle time.

“If you look into literature around SMED, it has been documented in manufacturing that up to 45% can be saved with each cycle of this process,” he added. “In our case, from previous history, we performed this through facilitated workshops around the world and have seen that the numbers come in around 50%.”

In the Eagle Ford workshop, Statoil started with drilling. The group came up with 98 different improvement ideas. Each of those 98 ideas was evaluated about how each shows up as potential time savings. These were then turned into 98 mini-projects. Each project will be turned into reality, although some projects may not be cost-effective, which means not all projects will become reality.

“It’s not just an idea, but we have a process to drive them into reality in the field, so we actually cut our cycle time,” O’Donnell said. “So far, 23 of those mini-projects have been completed, and there are 75 left to do. Each time one of those is completed, in theory, we improve our operation and reduce our cycle time.”

Statoil has been benchmarking its performance as an operator in the Eagle Ford. The company used Rushmore Reviews to benchmark the performance of the operators in the area, including the Norwegian company.

“Statoil was actually the most efficient at 755 ft/d [230 m/d],” he said. “If you look at the perfect well work and what we’re shooting for today, our next milestone is to hit the 20-day well. That’s a big milestone, which would put us somewhere near 1,000 ft/d [305 m/d]. And that doesn’t change around the world for onshore very much. If you’re averaging [305 m/d] in your operation, then you’re at the top or near the top in efficiency in your area. Not many companies can achieve that.” It remains to be seen how much efficiency can be gained in the hydraulic fracturing and completion areas for Statoil.

Trends in hydraulic fracturing

Fulks said service companies are focusing on helping clients achieve lower completion costs while at the same time increasing productivity by getting a better frac job, for example. On the side of lowering costs, the continued use of zipper fracturing is more efficient. Fuel substitution with compressed natural gas, propane, or even line gas can reduce diesel costs by up to 70% in certain cases.

“Smart scheduling is another trend,” Fulks said. “It’s basically service companies like ours working with our clients and saying, ‘Look, we can afford to give you lower pricing if you’ll help us manage our days-per-month asset utilization.’ If we can be setting up on the next well while we’re finishing this one, it’s a more efficient use of our assets. This has been going on a long time, but it’s becoming a little more formalized.”

A number of years ago, there was something called frac-on-the-fly. What service companies are doing now is real-time monitoring of frac jobs during the fracturing.

“We’re actually estimating the stimulated reservoir volume or stimulated rock volume by stage as we’re going along,” Fulks said. This is useful, for example, if an operator wants to determine whether sliding sleeves or plug and perf (PNP) would drain the best and be more productive without having to wait two years for production data. “How can we figure it out faster? You can actually figure it out fairly quickly right away,” Fulks said. “Let’s say you have a 10-stage well; you run five stages in the bottom as PNP and the other stages as sliding sleeve because most sliding sleeves now will work in a cemented application as well. You simply compare the stimulated rock volume or the estimated stimulated volume for each one of those.

“You can immediately see the impact through microseismic of what you think is happening to your formation downhole. Now microseismic is still qualitative more than quantitative, but it’s a very quick look at what’s going on downhole, and that’s kind of interesting,” he added. “Lastly, we think we can safely say that we see a trend back toward slickwater fracs and perhaps away from the more complex fluids. It’s not in every play but in quite a few plays.”

Fulks said that stacked lateral wellbores are another big trend that’s happening, particularly in the Permian and the Bakken.

“That is where you see multiple wells in basically the same service acreage and are simply doing more effective drainage of the given acreage position,” Fulks said. “You’re going to see multiple stacked pays in the Bakken and the Permian. One company that has some interesting diagrams out there right now is Laredo.”

Using data to improve efficiency, effectiveness

There are two areas that can address some of the challenges around fracturing – material sciences and computing power, according to Meisenhelder.

An example of gains through material science is the ELEMENTAL degradable alloy technology that degrades completely and predictably in a wide range of downhole conditions without the need for chemical additives. Components of the completion made of these materials will degrade on their own, eliminating steps in the completion and cleanout process.

Meisenhelder noted that on the efficiency side the industry is looking for a step-change from new technology. “In many cases we are approaching the technical limit for drilling and completing wells with the technology we have. The next step-change in efficiency will likely come from a game-changing technology,” he said.

Both Meisenhelder and Fulks pointed to the importance of computer models in improving cluster placement and effectiveness.

Increased computing horsepower can do a lot for the industry in planning clusters and stages, engineering completions, designing near-wellbore solutions, determining drainage area, and placing multiple wells and laterals, Meisenhelder explained. But the biggest single opportunity in the industry is still the low expected ultimate recovery. “How you double EUR is a big question out there, more so than cutting the cost of the well,” he continued.

Fulks described a trend called completing smarter, which uses LWD logs, cuttings analysis, or gas-ratio analysis to adjust the stage and packer positioning.

“Everybody’s been talking about it for a long time, but there’s been some recent success in the Eagle Ford,” he said. “Let’s say you’ve got 20 stages in the Eagle Ford. You simply arrange them better whether you’re using lithology, brittleness, total organic content, or some other algorithm of logging responses. We’re seeing clients with results that show 20% to 24% improvement in IP rates.

“Now, does that mess up your zipper design? It could. We recently conducted a small survey asking completion engineers, ‘If you could find a way to tweak your stage and cluster spacing but it gave you a 16% increase in IP rates, would you risk screwing up your zipper designs?’ And every one of them said, ‘Yes, we would.’”

Improving sliding sleeves

Controlling where fluids go is the critical part of hydraulic fracturing, Ely emphasized. “That is why the sliding-sleeve people are trying to develop multiple entry ports and cemented, multiple-entry sleeve systems,” he said. “The biggest problem is that you are having to deal with corrosion, scaling, and fines, which occur in opening and closing the sleeves.”

However, if technology can solve the problem, it would benefit restimulation efforts. The development effort is aimed at building a sliding sleeve that can be used to perform the initial stimulation and then three to four years later be used to close off the original openings and stimulate through new openings.

“If we can do that, we will add a new dimension to enhancing removal of oil and gas in place,” Ely said.

Having absolute control of where the fluids go is the reason why PNP completions are dominant in the industry. About 80% of completions use this method, he said.

Industry integration, crew training

Integrating different disciplines is something the industry talks about but is a lot harder to do, Meisenhelder said. “To really integrate, you need to challenge all disciplines with a single problem.”

Weatherford has worked with one major oil company that only wanted to work with a single, fully integrated company. The company told service companies that if their services didn’t include coiled tubing, wireline, plugs, and flowback along with the frac, don’t even bother. The company wanted to talk to a service provider that’s integrated.

“That really reduced its tender list,” Fulks said.

Weatherford has had great success with other companies in integrated completions. “We saw agreed-upon key performance indicators (KPIs) going up across the board, whether it was with the drilling side, the completions side, or even the artificial lift side by going to an integrated approach,” Fulks explained.

“Let’s say your KPI is going to be uptime. If there is any nonperformance time, nobody gets paid for it. Before, if the wireline company hit a snag and it cost six hours, the frac company still charged for standby time. However, in an integrated situation, basically it’s all for one and one for all. If there is a problem, nobody gets paid standby until the problem gets fixed. And I’ll tell you, that puts the onus on efficiency on the service companies. Some service companies embrace it, and those that don’t won’t even go near it,” he said.

Crew training is just as important as it ever was. Having a competency, a career path, and training is the heart and soul of this business, Fulks said.

“We certainly implemented our own training programs and continue to bring more people in and have them go through competency training,” he said.

In addition to its own training, Weatherford hired an outside consulting firm to offer additional eyes and ears on its training program. “The consultant basically runs its crews through the wringer just to see if they are field-ready to deal with onsite company

men,” Fulks said. “[The consultant] has a lot of wellsite consultants basically monitoring frac jobs for operators because it’s rare that an operator actually has its own personnel on location.”

Decline curve problems, refracturing

The industry currently spends a huge percentage of its capital on the first two months of the well life. The emphasis is on drilling and completing the well, Meisenhelder explained, rather than on managing the well for the remaining 30 years of life. “But how we manage flowback and production could be adding to production decline in wells. Production in some wells could decline so rapidly that the operator abandons the well rather than studying the problem,” he said.

Production practices can contribute to near-borehole fracture damage, fines from proppant crushing, scale, and mechanical changes in the rock – all of which steepen declines. “The technology exists to optimize the post-frac life of the well, but it comes back to having information. Without data about the reservoir or the rock you cannot explain why one well produces better than another or declines at a slower rate, nor can you identify a good refrac candidate,” he added.

“Almost by definition, normally fractured formations need to be restimulated because of a generation of fines, scaling, etc.,” Ely said. “The problem is that a lot of the techniques we’ve used are such that it is very difficult to restimulate. We’re working very hard on that problem and technology that we think will allow us to restimulate.

Bar association offers new guide for dealing with hydraulic fracturing issues

By Erica Levine Powers and Beth E. Kinne, American Bar Association

The American Bar Association is offering a 350-page book on Beyond the Fracking Wars: A Guide for Lawyers, Public Officials, Planners, and Citizens. The book provides an accessible and credible reference that covers the technologies and regulatory framework governing oil and gas development via hydraulic fracturing; case studies exploring the hurdles, pitfalls, and opportunities for creative solutions; and innovative approaches to managing the impacts of the “shale gale” on both the regional and international level. Written by authorities in a wide range of fields, this book is organized into four parts: Part I: Technology and industry overview, providing a detailed overview of the technology, structure, development, and relationships with regulators; Part II: Legal issues, providing the legal foundations, federal regime, and local approaches; Part III: Nongovernmental, governmental, community and industry perspectives, offering a series of case studies providing a basic understanding and viewpoint from real people in real places; and Part IV: Getting beyond the fracing wars, focusing on some less frequently addressed issues and challenging the reader to think broadly and deeply about the implications of current legal relationships and common practices. For more information on Beyond the Fracking Wars, visit ShopABA.org

Companies customize environmentally sustainable water treatment

Increases in water consumption and subsequent disposal issues are prompting operators to look for more economic and environmentally sustainable treatment options for produced and flowback water associated with hydraulic fracturing. To aid in that effort, Baker Hughes is partnering with DuPont Chemical Solutions to provide a self-contained, chlorine-dioxide- (ClO2-) based treatment solution that both companies believe will lead to best practices for oilfield water treatment.

Baker Hughes is using custom-engineered generators from DuPont as well as its expertise in the application of ClO2 to ensure safe and efficient generation of ClO2 in its H2PrO HD service to treat hydrogen sulfide (H2S), and bacterial contamination. Baker Hughes has ruggedized the generators to withstand harsh oilfield conditions and fitted them to the company’s treatment trailers.

ClO2 has been used for more than 60 years in municipal drinking water, food processing, and industrial applications. For more than a decade it has been used in refinery treatments. Today that use is expanding to hydraulic fracturing treatment; remediation of near-wellbore damage in production, injection, and disposal wells; and as a biocide for water in surface storage. Its unique chemical and biological properties are capable of quickly and efficiently removing contaminants and treating the water to support successful fracturing fluid design.

ClO2 is a selective oxidizer that works at low dosages and offers a broad range of bacteria, fungi, and virus destruction. As a gas in aqueous solution, it penetrates and sloughs biofilm, mitigating the destructive bacteria. It is nontoxic, approved by both the EPA and FDA, and does not form trihalomethanes (THMs), assimilable organic compounds (AOCs), hypochlorous acid, or free chlorine. It is less corrosive than chlorine and oxidizes manganese, iron, phenols, sulfides, cyanides, and odor-causing substances.

As part of the H2PrO HD service, ClO2 is generated onsite via a mobile or permanently mounted DuPont generator. The vacuum-based system dramatically improves safety by creating the ClO2 in the water flow rather than pumping it or using a reaction chamber. The treatment provides a powerful biocide that neutralizes bacteria, H2S, iron sulfide, phenols, mercaptans, and polymers in the water. By neutralizing these substances, the treated water can be reused with no negative impact to chemicals used in hydraulic fracturing, the producing formation, or to downhole equipment. The water management service includes pre- and post-water testing to ensure compliance with operator water quality standards.

With fast chemical reaction time, concentrated solutions, and high ClO2 generation rates, the service can treat up to 600,000 bbl of water per day with a single unit. The mobile generator system can be set up very quickly – often in just one hour.

In 2013, more than 40 million barrels of water and 600 wells were treated with the H2prO HD service in hydraulic fracturing operations in the Permian basin, South Texas, the US Rocky Mountains, and Northeastern US shale plays.

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