Unconventional Resources Technology Conference Research Articles

Chevron Applies Some Unconventional Thinking To Try To Make Shale EOR a Standard Treatment

In the shale business, the closest thing now to enhanced oil recovery (EOR) is improved techniques. During an earnings call last November an analyst asked EOG Resources executives about their enhanced completion technique which EOG reported was adding 20% to first-year well production in the Permian. Improved completions have allowed operators to significantly increase early production year after year, but after that, steep declines are a given. Back in 2016, EOG was talking about how it was increasing oil production significantly by injecting millions of cubic feet of gas a day into wells in the Eagle Ford. It triggered an EOR field-testing boom by competitors hoping to match reported reserve increases of “30 to 70%.” In a 2017 JPT story, Deepak Devegowda, a petroleum engineering professor at the University of Oklahoma, said, “This is the name of the game. Everybody is talking about EOR and pumping money into trials of EOR.” Now the only mention of the acronym EOR on EOG’s website is an item in its corporate history timeline for 2016: “We commercialized the first enhanced oil recovery process, or EOR, in shale.” In recent years, reported shale EOR work has been mostly in the form of occasional papers describing production uplift by companies selling ways to increase production by injecting gas or chemicals. EOR effectiveness isn’t the issue, according to Todd Hoffman, a petroleum engineering professor at Montana Tech University who wrote two papers evaluating EOG’s methods cited in two Chevron papers. “The EOG field work showed us that these projects can produce significant additional oil and be economically positive,” he said. The problem is that drilling and fracturing wells delivers “higher economic returns than the EOG-style EOR projects with the huge compressors, high gas rates, and high injection pressures.” Last year in the middle of this EOR drought, Chevron did something different. It delivered two papers revealing a major company-scale effort to find ways to use chemical and gas injections to economically produce more oil. The papers presented at the 2023 Unconventional Resources Technology Conference (URTeC) reported on field tests of surfactants and natural gas injection on Permian Basin wells which delivered sufficiently encouraging results to justify an expanded testing program. (URTeC 3870505 and URTeC 3871386). Chevron described a systematic effort by its corporate technical unit and its Mid-Continent business unit to rethink shale EOR methods based on the unconventional nature of flow through fractured reservoirs and the economic realities in a business where new EOR technology is competing with the profitable status quo. Its methods challenge accepted notions about the role of EOR. In SPE’s disciplines, EOR normally falls under the production topic, “marginal aging fields.” What Chevron tested is better described by the topic, “well interventions.” Rather than looking at these techniques as a way to eke out the last barrels from old wells, the papers describe methods that can be deployed earlier in the life of these short-lived wells.

Are We There Yet? Tight-Oil Producers Still Chipping Away at Parent-Child Problems

In June, ExxonMobil’s CEO announced at an investor conference that the oil giant is experimenting with “very promising new technologies” poised to substantially enhance its recovery rates in the Permian Basin. Darren Woods was light on specifics. Nonetheless, ears perk up when the head of the largest oil producer in the US suggests that it’s making progress on its goal to double the oft-cited and oft-derided 10% recovery factor of shale resource plays. What Woods clued the outside world into is ExxonMobil’s optimism around drilling extra-long horizontal wells (17,500-ft laterals vs. the more-typical 10,000 ft) and the work that engineers are doing to make sure such wells can be effectively propped. Both count as compelling kernels to chew on. But the CEO alluded to another area of notable progress when he said, “There are very few companies or organizations out there that could tell you exactly how fracs propagate and what that looks like underground—our view is that’s just a hard science project problem to solve.” A couple of weeks later, the largest oil and gas producer in the US shared a much more in-depth assessment of that science problem at a different industry gathering—this time the Unconventional Resources Technology Conference (URTeC). In URTeC 3860704, two dozen authors from ExxonMobil describe a four-well test used to steer decision making in the Midland Basin side of the Permian where it is among those drilling massive multiwell projects known as cube developments. The experiment raised enough red flags for ExxonMobil to rethink its plans for a tight-well design. Multiple sources of data showed the wells were too close, their fracture networks in too much communication. “These results suggest the pilot location was overcapitalized and that future developments should be drilled at fewer wells per section,” the authors concluded. Those are not words that an oil company generally likes to hear. However, the point is that ExxonMobil learned of a poor outcome on a small scale which ostensibly preempted further financial pitfalls at the location. Cautionary tales such as Concho Resource’s 23-well “Dominator Project” in 2019 have demonstrated to all tight-rock producers—and particularly Permian cube developers—the consequences of insufficient subsurface analysis. In the words of ExxonMobil’s engineers and other specialists, “This integrated project clearly established the value of running diagnostic pilots and collecting high-resolution data before, during, and after completions to quantify the size and shape of the fractures created and propped extent of the stimulated rock.” ExxonMobil’s latest study is one of several published this year to suggest that while the work is far from complete, significant leverage is being gained over the parent-child phenomenon. Another big operator known for keeping a close eye on fracture propagation announced it has developed a tandem of new models to help improve parent-child relationships in the Eagle Ford Shale of south Texas.

Big Fracs That Add More Oil May Also Mean More Water, and That Can Be All Right

A few years ago, Occidental Petroleum managers were puzzled by why their recent Permian Basin wells were producing more water per barrel of oil, so they asked some engineers to figure out what was wrong. Their concern was understandable. While the company’s well evaluation system was supposed to screen out prospects likely to become big water producers, the amount of water flowing out of wells in the Delaware Basin drilled after 2018 far exceeded volumes from previous years. “We found that newer wells had a steeper increase in water cut over time than older wells,” the coauthors of an Occidental paper wrote about the work done to answer the question. They added, that “pre-2018 wells had an average water cut increase of 4% in the first 300 days (after cleanup) and then stayed relatively flat after 300 days, whereas post-2018 wells’ water cut increased at an average of 12% in the first 300 days and 16% in the first 600 days before reaching a plateau” (URTeC 3720245). Those trends, plus wells ultimately reaching an 80% water cut, suggested that a string of wells may have been drilled into water aquifers. While that is a risk in the Permian, the evidence suggests that the geology in the wells they compared was similar before and after 2018, even though the water cut levels were not. A big difference was how the wells were fractured. In 2018 Occidental began doing bigger fracturing jobs, using more water and sand per foot, which increased the number of stages and fracturing clusters. Those changes added oil production because “high conductivity speeds production and enhances the well’s net present value,” said Samuel Amadi, a senior reservoir engineering advisor for Occidental, while presenting the paper at the recent Unconventional Resources Technology Conference (URTeC). Based on production records, the water/oil ratio also was higher. Using data from comparable wells before and after the completion design changes, a model was created that quantified the relationships between fracturing designs and the oil, water, and natural gas flowing out of Occidental wells. “One recurring observation in all these completion scenarios is that a better-completed well will have higher fluid withdrawal and a steeper water cut trend after cleanup than a poorly completed well for the same reservoir and operating conditions,” the paper’s authors wrote. A coauthor, Xueying Xie, principal and manager of unconventional recovery design at Occidental, added that based on her team’s simulations, “we know we are not doing something wrong. This is doing a better job. It speeds production.” But unlike a well drilled through a fault connecting it to an aquifer, there was a limit to the water produced from these extremely tight formations. Like the oil production in more aggressively completed wells, the water production peaked at a higher level than the less intensely fractured wells but declined over time to a similar level. “On the water production side, just the pace changes,” Xie said.

The Sound of One Fracture Flowing

In November 2020, Gustavo Ugueto had an extraordinary in-well experience. The source of his amazement was a stream of fiber-optic data measuring how fractures were altered by slight pressure changes during production. When the principal petrophysicist for unconventional technology at Shell described the Permian well test, he sounded like someone who had used a stethoscope for the first time. “The straining is extended and compressed at all times like breathing,” Ugueto said during a presentation at the 2021 Unconventional Resources Technology Conference (URTeC) about the test done at the Fracturing Test Site 2 in late 2020 (URTeC 5408). He said it was an “aha moment,” as was getting a good signal considering the infinitesimal differences in the fracture dimensions in a well where the daily pressure drop was less than 40 psi. And he was excited to think about what this test could reveal someday about how fractures change during production. If it lives up to that potential, “we will have the ability to measure. We can experiment. What type of treatment? What type of proppant? We can do more of the good one and less of the bad one. The problem [now] is we have been working blind,” he said. While he was clearly excited about the potential, he also repeatedly cautioned that there is so much more work required to learn what is possible. At this point, the few people with access to this data are like new medical students using a stethoscope, wondering how those sounds related to the patient’s health. “We are at the beginning of journey; it may fail,” Ugueto said. The New Strain The data from the Hydraulic Fracture Test Site 2 are only available now to those who backed the project, but three papers cover the work (see For Further Reading), sparking others to try this new way to measure fractures. “Because of the publications by Gustavo and his coauthors, we are seeing a lot of uptake based on what was learned,” said Dana Jurick, Neubrex Energy Services US—the company that supplied the equipment used to measure the strain data. The company has since been hired for similar work by other oil companies curious about what they can learn from this new diagnostic. The coauthors include Ge Jin, an associate professor at the Colorado School of Mines, who was a geophysics consultant at the Hydraulic Fracturing Test Site 2, and Kan Wu, an associate professor at Texas A&M, who is collaborating with Jin. Her group at Texas A&M is working on modeling aimed at turning this qualitative data source into a quantitative measurement. Ugueto said other operators trying it, including Chevron and ConocoPhillips who were among the test site partners, plus other fiber-optic companies, are getting into a field that is so new there is no settled name for it. Two commonly used labels for it reflect varying levels of optimism about its future. One is based on the data gathered: near-wellbore strain analysis. The other is based on a vision where it is possible to measure how fractures react to change: near-wellbore fracture dynamics.

Unconventional Reservoirs: Australian Exploration Experts Weigh In on Rosy Reserves Estimates

The early days of a new shale play can be exciting, but they can also come with inflated expectations. This is a familiar theme in the unconventional sector which has delivered a myriad of discoveries over the past decade that have failed to achieve commerciality. It’s especially familiar for those involved in Australia’s unconventional projects where big hopes have been pinned on the tight-gas potential of places called the Beetaloo, Canning, and Cooper Basin. Instead, the only long-term success to be found on the Australian unconventional landscape is a mature coal-seam gas sector which, not to be discounted, helped the country claim the status of the world’s top exporter of liquefied natural gas in 2020. For Duncan Lockhart, one of the chief reasons that Australia’s tight-gas ambitions have yet to materialize likewise lies in the fact that tight-rock plays extend for vast areas compared with even the largest conventional systems. As a result, the general manager of exploration with Brisbane-based Central Petroleum said some of the estimates on unconventional prospective resources are “verging on fantasy.” Lockhart issued his critique as a co-chair of a resource valuation panel hosted by the Asia Pacific Unconventional Resources Technology Conference in November 2021 The discussion between several exploration experts tried to identify the biggest missteps in Australia’s tight-gas adventure thus far. At the highest level, the industry depended on the promising results of too few appraisal wells to formulate reserves estimates on areas covering hundreds and sometimes thousands of square kilometers. Lockhart emphasized in trying to evaluate such “massive areas,” operators and appraisers have been pushed into a corner. “We need to make a whole bunch of major assumptions about a whole bunch of inputs,” he said, adding that left out of the initial estimates all too often is “the amount of heterogeneity that we will be experiencing in these rocks over these large areas.” Lockhart was not alone in his concerns. With hindsight, it has become easier to see that the highest-performing wells tend to be drilled in isolated sweet spots and along narrow fairways—not across the entirety of a play’s geographic boundaries as shown on the map. The risk facing every operator in this situation is that it will burn through its capital on the wrong slivers of shale and, in turn, see its investors run for the exit. Martin Wilkes, a managing director with energy consulting firm RISC Advisory in Perth, took aim at what he characterized as the “sales message” approach that tends to ignore such facts of life during the early promotion of tight-gas plays. “[Operators] talk up total organic compound content and use it to develop these large numbers, which then get transferred into a continued resource using standard recovery factors,” he said.

A New Recipe for Friction-Reducer Suppliers: Polymer Plus Frac Water, Minus the Cost

The argument for making friction reducer on site is simple: only one truck is required to deliver dry polymer vs. three loads required for the same amount of liquid additive. For Downhole Chemical Solutions (DCS), reducing the number of trips and the amount of chemicals needed to create a stable liquid by mixing it as needed on site reduces the average cost of a gallon of friction reducer by around 30%, said Mark Van Domelen, vice president of technology for DCS. “The business is very cutthroat and competitive on the pricing of polyacrylamide. We can reduce the cost further on friction reducer,” using dry polymer, he said. Polyacrylamide is generally described as the key component in friction reducers. Suppliers also add some ingredients to create a stable liquid and others that are supposed to improve performance. When DCS delivers dry polymer to a well pad to mix it on-site, the only other ingredient is water provided by the customer. It has been a winning strategy change for the private company; it has grown rapidly, even during last year’s slump. DCS increased the number of mixing units from one to 16, and dry polymer sales have grown from 10% to 90%, Van Domelen said. One of the company’s customers is John Blevins, the chief operating officer for Houston-based Hibernia Resources III and an early adopter who was a lead author of a paper on making friction reducer on site while fracturing (SPE 204176). Blevin, who uses the words “friction reducer” and “polymer” interchangeably, is the rare C-level executive who likes to manage operations from a frac van at a company that normally completes one pad at a time. The polymer is polyacrylamide. When Blevin works with DCS on a well, he purchases it directly from one of the few chemical companies that will produce the polymer based on his specifications. The price on the DCS invoice will be a price per pound that covers the cost of the polymer and the service. At Hibernia, a small private-equity and employee-owned company, there is a powerful incentive to pay close attention to the details. “When we spend a nickel, that nickel is divided among us at some point in time. If we are efficiently frugal, we are going to be better off in the long run,” Blevins said. The paper, which was presented at the Unconventional Resources Technology Conference (URTeC), included a chart showing stage-by-stage costs, with the average cost for dry stages ranging from 27% to 31% lower than similar stages that were fractured using liquids. The simplicity of the mix is a plus for Blevins whose company is especially focused on how chemicals are likely to react downhole. “We did a 6-month study before we pumped anything in the ground to make sure we had the right combination” of fracturing additives, he said. “We do study nearly every well and every landing zone to ensure the chemicals used are compatible.”

What’s the Best Friction Reducer? You Need To Figure It Out Yourself

Friction reducers are expected to play critical roles in fracturing, some better than others. Shale producers are belatedly realizing that there are many variables that can alter the performance of these chemicals used to reduce the power needed to hydraulically fracture a reservoir, and in higher doses, to thicken fluid, making it possible to deliver proppant more efficiently. There are wells that can justify paying more for a friction reducer formulated to stand up to difficult chemical challenges, and others that cannot. But there is no guide that describes how these key additives perform. Those who do evaluations will realize that a lot of details about friction reducers are proprietary and no industry standard provides guidance about the information needed to thoroughly assess their compatibility with reservoir conditions. “There hasn’t been a really good method to quantitatively evaluate friction reducers and what they do,” said Paul Carman, the completion fluid advisor for ConocoPhillips, who has not figured out what that method might be. Recently, Occidental Petroleum took a stab at answering the question with a paper discussing its evaluation of friction-reducer performance. It’s not a short answer. The paper delivered at the Unconventional Resources Technology Conference (URTeC) does not offer names of the products tested, how many were tested at any stage of the process, or details that might identify top performers (URTeC 5249). Those who dig deeper and ask fracturing experts will learn that the best friction reducer will depend on the job. And money, time, and research are required to gather the data needed for informed decision making. When Occidental began working on a system to evaluate friction reducers, they found little had been written on how to do it, said Nancy Zakhour, Occidental’s well design lead, a coauthor of the paper. There was a general paper from Shell on well chemical evaluation but little else. That shows how oil companies have come to rely on others to do performance testing. The shale business has not shown much interest in chemical performance until recently. Greater attention has turned to the many details that can incrementally improve shale well performance and to the research showing how friction reducers perform badly due to chemical reactions in some wells. These are not the only additives that may be affected by chemical reactions during and after fracturing. But friction reducers have grabbed the most attention because they do a couple important jobs.

Automated Mud Skid Holds Promise of Safety, Efficiency Improvements With Real-Time Fluid Monitoring

As industry buzzwords go, “automation” has spent its time in oilfield vernacular climbing the ranks of widely used terms. It now resides as one of the go-to designations for signs of advancement in any number of disciplines. Its use has been tied most frequently with drilling operations as contractors look to keep employees out of harm’s way via a robotic take-over of most motion-intensive jobs on the rig’s drill floor—basically anything that grips, clamps, or spins. More recently, the term has moved away from the drill floor and into other well construction operations allowing for things such as remote, real-time measurements without the need for boots on the ground. For areas like west Texas and the Permian Basin shales, having the option for remote readouts and a component of automation that can allow for corrective actions should the need arise can go a long way in terms of safety and efficiency gains as well as better manpower application. Unsurprisingly, the area has become a solid testing ground for new, expanding efforts in automation. With dreams of new drilling-fluid-monitoring automation, Eric van Oort, a professor at The University of Texas at Austin and former Shell research scientist, and select students came up with a new way to automatically measure mud parameters such as viscosity without the use of a traditional viscometer. “The fact that we still use manual measurements, some of them now 90 years old, is quite puzzling in this day and age,” van Oort said. “The Marsh funnel, for instance, was introduced in the 1930s, and other mud tests go back to the 1950s and 1960s. These API measurements have served us well, but the question is, can you do something more now with modern measurement techniques and sensors? So, I started working on new ways of measuring the viscosity and density, and then later fluid loss and even solids and salinity in muds. That proved to be all very successful and promising.” Construction of a mud skid to house the equipment and sensors needed to conduct these tests in real time was the next step in the evolution of van Oort’s concept. That initial skid was a cannibalized and reworked version of a unit that was employed on Shell’s Rig 1, which the supermajor built for its in-house rig-automation research based in Pennsylvania. This early mud skid, considered the prototype of van Oort’s design, was abandoned before it was properly tested. “We generated quite a bit of IP [intellectual property], my students and I at UT,” he said. “The Shell skid hadn’t seen a significant amount of service, and it had some nice components that we could reuse. We took that skid apart and reconfigured it and put it out in the field with Pioneer Natural Resources for a set of field trials in the Permian. Those went well.” The field trial results were shared in a paper presented at the 2019 Unconventional Resources Technology Conference (URTEC 2019-964). The paper concluded that the pipe viscometer employed by the skid allows for the characterization of additional rheology parameters, which cannot be obtained with Couette-type viscometers, such as the critical Reynolds number, characterizing the transition from laminar into turbulent flow, and the friction factor in the turbulent flow regime.

Data-Mining Approach Evaluates Production Performance in the Permian Basin

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper URTeC 198192, “Production Performance Evaluation From Stimulation and Completion Parameters in the Permian Basin: Data-Mining Approach,” by Mustafa A. Al-Alwani, SPE, and Shari Dunn-Norman, SPE, Missouri University of Science and Technology, and Larry K. Britt, SPE, NSI Fracturing, et al., prepared for the 2019 SPE/AAPG/SEG Asia Pacific Unconventional Resources Technology Conference, 18–19 November, Brisbane, Australia. The paper has not been peer reviewed. The complete paper uses 3,782 unconventional horizontal wells to analyze the effect of proppant volume and the length of the perforated lateral on short- and long-term well productivity across the Permian Basin. Tying cumulative production to completion and stimulation practices showed that increasing pumped proppant per well from 5 million to less than 10 million lbm yielded a 34% increase in 5-year cumulative average barrels of oil equivalent (BOE). Raising the pumped proppant per well to 10 million-15 million lbm and 15 million-20 million lbm increased 5-year cumulative BOE from the previous proppant range group to 27% and 18.5%, respectively. Introduction For this study, stimulation chemical data from Permian (Midland) Basin wells were downloaded from FracFocus for all horizontal wells completed and stimulated between 2012 and 2018. The data were then subjected to rigorous cleaning and processing, a process detailed in the complete paper, and then combined with DrillingInfo completion and production parameters. Combining these data provided ample parameters for stimulation, completion, and production data. The objective of the study was to investigate the production performance of Permian Basin wells as a result of different ranges of stimulation and completion parameters. Fig. 1 shows a database representation of the major counties in the Permian Basin with the number of wells in each county. Results and Discussion To substitute for any quantities of produced gas, all production data have been converted to BOE by using the conversion factor of 1 BOE=6 Mcf. The amount of proppant being pumped and the length of the perforated lateral length have been selected to represent the stimulation size and the completion magnitude, respectively.

How to Make Better Investment Decisions in Unconventional Projects

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper URTEC 198318, “How Not to Squander Billions on Your Next Unconventional Venture,” by Creties Jenkins, SPE, and Mark McLane, SPE, Rose and Associates, prepared for the 2019 SPE/AAPG/SEG Asia Pacific Unconventional Resources Technology Conference, Brisbane, Australia, 18-19 November. The paper has not been peer reviewed. During the past decade, hundreds of unconventional oil and gas projects have failed to deliver the value sought by shareholders. Two common mistakes have been focusing on production attainment instead of value creation, and incorrectly thinking that enough was understood about a given reservoir to proceed with development. Companies must implement a staged approach that exposes capital incrementally in a responsible fashion and an assurance process that provides a framework for conducting and reviewing work so that mistakes may be analyzed to influence future decisions. The complete paper provides a work flow for making better decisions about investing in unconventional projects. Introduction In 2019, an analysis of 16,000 unconventional wells operated by 29 of the largest producers in Texas and North Dakota revealed that these companies spent $112 billion more in cash over the past 10 years than they generated from operations. A primary contributor to this shortfall was optimistic production forecasts based on a small number of early wells. These types of projections lead companies to commit to development projects before they understand the true variability in well performance and, most importantly, whether the average well will be commercial (i.e., able to pay for the cost to drill, complete, and tie in). Commercial is defined here as attaining a present value greater than zero at the corporate discount rate. If this is 10%, a net present value (NPV) of zero equates to a 10% rate of return. The Challenge More than 50 shale plays across North America have been tested for their production potential. Of these, only a dozen or so (approximately 25%) have been commercially developed. Thus, the first order of business is to focus on the right play in the right basin. But even within a productive basin, operators need to be in the commercial fairway, which is commonly a fraction of the total basin area regardless of play type. The probability of commercializing a new unconventional play in a frontier basin is low. Although a well can be drilled practically anywhere in the basin and encounter mobile hydrocarbons, this does not reduce the commercial risk relative to conventional plays. Instead, it transfers the risk (threat of fiscal loss) to later stages, in which it must be shown that unconventional wells can produce at sufficient rates, costs can be reduced to make these wells commercially viable, and results are repeatable.

New Method Determines Well Spacing in Unconventional Reservoirs

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper URTeC 2584, “A New Methodology To Determine Well Spacing in Unconventional Reservoirs: Delaware Basin Study,” by Dicman Alfred and Andrew Lundy, Scala Energy, prepared for the 2020 Unconventional Resources Technology Conference, originally scheduled to be held in Austin, Texas, 20-22 July. The paper has not been peer reviewed. Present industry solutions to the challenge of well spacing involve expensive geomechanical Earth modeling or fracture-geometry monitoring that is time-consuming, data-intensive, and geography-specific. The authors of the complete paper write that their developed methodology is quicker and pad-specific and requires no additional data collection than those routinely gathered. Other significant outcomes of this work flow include the ability to rank well performance and predict changes in geology and pressure regimes relative to an existing similarly landed producer.

Bringing the Heat: Aramco Field Tests High-Temperature Chemistry To Slash Tight-Gas Completion Costs

By turning up the temperatures downhole, you need less of every-thing up on the surface. This is what is hoped to be proven soon with an experimental chemical technology that is seeing some of its first field tests in Saudi Arabia’s emerging tight-gas formations this year. The innovation centers around reactive chemicals known as thermochemicals that researchers at Saudi Aramco and King Fahd University of Petroleum & Minerals (KFUPM) in Dhahran spent most of the past decade developing. When it comes to unconventional applications, the world’s largest upstream company has two big ambitions. First, it is introducing a new hydraulic fracturing fluid that shaves millions of dollars off the cost of horizontal wells by more than halving the amount of equipment and water typically needed to stimulate the wells. Second, it aims to reduce the number of unproductive fracture stages and the required number of stages by improving stage productivity. “It’s like a hybridization of pulse fracturing and hydraulic fracturing,” explained Ayman Al-Nakhli, a chemist and petroleum scientist at Saudi Aramco’s EXPEC Advanced Research Center. “The thermochemical will create a pressure pulse downhole to break down the rock - then we can propagate the fracture with hydraulic fluids.” Al-Nakhli recently shared new details about the technology at the virtual 2020 Unconventional Resources Technology Conference (URTeC) while presenting a technical paper (URTeC 2439) that he authored with colleagues and university collaborators. The paper outlines laboratory tests in which samples of shale rock from the US and elsewhere were fractured using traditional slickwater fluids alongside the thermochemical approach - or what Al-Nakhli calls the “ExoFrac.” While validation awaits, the years-long research and development project is a reminder that as Saudi Aramco seeks to develop the Kingdom’s tight-gas resources it is not relying solely on the North American experience or its suite of established technologies. The tests highlighted during the conference showed that when pumped into core and other rock samples at the initiation of small-scale hydraulic fracturing treatments, the chemical agents undergo an exothermic reaction that creates a pressure pulse strong enough to induce a fracture in the rock. Meanwhile, as the chemicals reach temperatures that may exceed 270°F, nitrogen gas is rapidly generated inside the fracture which increases its in-situ pressure. As it is drawn up for a real-world application, pumping the thermochemicals downhole would take roughly 5 minutes. Once the reaction is activated, the pressure pulse lasts only milliseconds. The high-temperature reaction continues for no more than 10 minutes before all the heat is absorbed into the surrounding formation.

When Fracturing, Heed the Plugs

Plugs used in fracturing do more than just plug. In addition to isolating stages during fracturing, they often provide the first warning when casing has been deformed - an all-purpose description for pipe that has been bent, squeezed, or gashed. A vague label for the damage is useful because most often those dealing with the problem will never know more about the damage than the inner diameter of the casing has been narrowed - ovalized is the popular term for it - and that they need to find a smaller-diameter tool to get past the obstacle. Eric Davis, the global completions chief for ConocoPhillips, offered a rare public presentation about what can be learned by digging deeper into the reasons why a plug, frac gun, or bottomhole assembly (BHA) cannot pass through a casing diameter. A major message in a panel discussion during the recent virtual 2020 Unconventional Resources Technology Conference (URTeC) was that investigating casing can yield surprising results. Davis told the online audience he hoped the presentations would “scare you into getting more data.” Davis shared an observation made while watching fracturing in progress on a screen displaying temperature and acoustic data collected by fiber-optic cables attached outside the casing for distributed temperature sensing and distributed acoustic sensing. As the stage progressed, cooler injected water (shown in green) mixed with the warm reservoir fluid (in blue) (Fig. 1). Temperature data from the fiber-optic cable showed the previous stage as all blue, indicating the plug was sealing. Then the colors of the previous stage started changing as cooler water leaked in and green streaks began bleeding into the blue of the previous stage; then “it all went blank.” The fiber had been severed, Davis said, adding that seeing it in real time “was quite shocking.” The fiber optic was still working on the yet-to-be-fractured upper stages, but “as we moved up the hole, we kept parting the fiber.” For the team involved it was a big loss in terms of the cost of the fiber installation and the data they had planned to collect. But for Davis the value of what was learned after the fiber was cut “is far more valuable than the lost fiber-optic installation.” Collecting the information required sending diagnostic tools downhole to inspect the damage. Gashes were found in the casing. They appeared to have been cut by the fast-flowing water-sand mix that may have begun as a small leak, grew in volume, and severed the metal tube holding the fiber-optic cables on the outside of the casing. “You can see it looks like the packing element is where the erosion occurred on a lot of cases,” Davis said. They also learned that the metal in the casing is softer than the plugs. Davis said, “We were preferentially eroding casing over the plug.” They found “total casing breaches” created by the high-pressure stream of fluid and sand on 25% of the plug locations examined on multiple wells.

Oil’s Wisdom Heats Up Drive for Geothermal Energy

Oil and gas are not the only things in the ground that can power our lives. Heat in the form of geothermal energy is rapidly taking its place alongside other sources of renewable energy, buoyed by the lessons learned from decades of drilling for oil. “Geothermal is this fantastic resource,” said Susan Hamm, director at the Geothermal Technologies Office in the US Department of Energy. “It’s an always-on renewable energy resource that harnesses the Earth’s natural heat. It improves domestic energy security and flexibility.” These benefits and challenges are the basis of the Geo Vision report (https://www.energy.gov/eere/ geothermal/geovision) created by the Energy Department. Hamm, along with Tim Latimer, the cofounder and chief executive officer of Fervo Energy, a company working on geothermal energy, and Aparna Raman, president of reservoir performance at Schlumberger, spoke during the Unconventional Resources Technology Conference. Hamm and Latimer laid out the benefits of geothermal sources of energy beyond its renewability. “It provides dispatchable baseload power,” Hamm said. “And this dispatchable nature is really key. You can turn it on, you can turn it off. You can turn it up, you can turn it down.” “It not only produces clean power,” Latimer added, “it does it around the clock, 24/7. It’s a fantastic complement to wind and solar resources to decarbonize the hardest parts of the electric grid.” Hamm mentioned that geothermal complements wind and solar by being widely available, pointing out that geothermal sources are available across the United States (Fig. 1). She also touted geothermal’s reliability, saying that, while solar can provide energy 20% of the time and wind 45% of the time, geothermal sources can provide energy more than 90% of the time. “In order to have a geothermal resource, you need to have three things,” Hamm said. “You need to have heat at depth, which we’ve already shown is everywhere, just in differing amounts. You need to have a fluid in the subsurface, and you need to have pathways for that fluid to move around to get the heat so you can get it back out.” An enhanced geothermal system (EGS) is a system wherein one or more of those aspects is created where it did not previously exist. “You either fracture the subsurface or you add water, or you do both in order to be able to recover that stranded heat.” Latimer, who began his career as a drilling engineer, turned toward geothermal sources after working in the Eagle Ford shale, where high temperatures were a problem to be solved. In solving the high-temperature problem, he said cues were taken often from the geothermal industry.

Water, Water Everywhere Using ML and Game Theory To Win at Produced-Water Forecasting

In the Bakken-Three Forks play of the Williston Basin, many oil wells that once produced some water have become water wells that produce some oil, as average oil production has flatlined while water production continues to increase. A complex interplay of stepping out beyond the core to where water saturations are higher, upsizing completions, tighter spacing, and dealing with greater parent-child effects and potential changes in relative permeability is significantly increasing volumes of produced water. Similar situations have been occurring in other basins. This is a serious threat for the US unconventional oil and gas industry, for which produced water has become a $34-billion industry and exposes operators to numerous operational, environmental, and economic risks. Software developers are beginning to adapt advanced machine-learning (ML) methods that have proved successful in forecasting oil production and upgrading them with aspects of game theory to make quick and accurate work of understanding and predicting water production in unconventional plays. Novi Labs (Novi), an Austin-based software company focusing on unconventional shale, has developed a solution that is being applied successfully in the Williston Basin to help disentangle the complex interactions of larger completion designs, changing geology, and tighter spacing that contribute to increased water production. According to the firm’s model, fluid per foot ranks as the most important input variable for increasing water production, ranking above proppant per foot and geologic parameters. Ted Cross, technical advisor at Novi and former senior geologist with Conoco Phillips, presented a paper that discussed the produced water challenge at the 2020 Unconventional Resources Technology Conference (URTeC). “How often does an engineer dash off a simple water forecast, doing something like applying a flat water-to-oil ratio to their water prediction?” Cross asked rhetorically. In unconventional oil fields, water forecasting and pre-drill water predictions have not received attention commensurate with their economic importance. “Quick is still common,” he said. Operators, regulators, and water-disposal companies often rely on simplistic water-cut ratios or basin-level extrapolations that ignore the complex interplay of geology, completions, and spacing decisions on water production. “They are starting to realize and incorporate the fact that water-to-oil ratios will evolve over a well’s life, usually increasing. But the critical thing is that the time they spend on water prediction is a tiny fraction of what they spend on oil, and the methods are less sophisticated and developed,” Cross said. Part of the reason, he explained, is that in the early development of the Eagle Ford, Permian, and some core parts of the Williston, either the original wells didn’t produce large volumes of water or the existing infrastructure around conventional plays was sufficient to handle it. But with field evolution and changing completion designs, water has become a critical issue.

New Fracture Diagnostic Test Delivers Tight Reservoir Data in 2 Hours or Less, Bolsters Future of Engineered Completions

One of the grand challenges facing the oil and gas industry’s global quest to improve the potential of tight reservoirs involves designing horizontal-well completions that match the often-complex heterogeneity of the target formations. This sums up the general concept most call the “engineered completion.” In theory, tailoring a stimulation job to the varying rock properties found along the lateral section of a horizontal wellbore should result in better production for less capital. In practice, the industry has never attempted to do this on a meaningful scale. Among other reasons, the detailed subsurface data required to shake the bonds of geometric, or “cookie cutter,” designs have long been considered too costly to gather or too time-consuming to analyze. A shift is underway though. This is thanks in part to a number of innovations that have hit the market in recent years to meet rising demand for real-time completions-monitoring services. By interpreting pressure signals and other reservoir responses, the new tools aim to give operators the competency they need to adjust fracture designs as the stimulation progresses. But there is another route to the engineered completion. It begins before the well is hydraulically fractured. This effort to predetermine different fracture-stage designs has established its own distinct arena of innovation. Behnam Zanganeh, a former research student at the University of Calgary, was part of a team that developed one of the latest approaches. It is notable in part because it requires no new technology - just new ways of thinking about some old ideas. In a paper published last month during the virtual Unconventional Resources Technology Conference, Zanganeh and his fellow petrotechnical researchers showed how multiple points in a wellbore can be tested for different reservoir-quality parameters quickly and simply relative to traditional methods (URTeC 2838). This is done by combining and fundamentally altering a test known for being slow: the diagnostic fracture injection test (DFIT). The biggest change it calls for is to start flowback after the injection cycle for flowback analysis (FBA), thus eliminating the lengthy falloff cycle associated with the DFIT. The paper outlines a validation study done with Sydney-based Origin Energy which used the blended DFIT-FBA method in a vertical open hole to test two previously untested horizons in the Beetaloo Basin, a frontier unconventional gas play in the center of Australia’s Northern Territory. The results were integrated into the models Origin ultimately used to select its landing target for its subsequent horizontal program.

Questions Over Permeability Prompt Producer-Led Group To Rebuild Key Fracture Diagnostic

For the past 20 years, the diagnostic fracture injection test (DFIT) has been used across the frontlines of the shale revolution to paint a picture of what cannot be seen. However, that picture has not always been so clear in the eyes of subsurface engineers. It is not the test has been questioned. It is the way a DFIT is analyzed. Last year, a joint-industry project supported by six shale producers formed to develop a new methodology that aims to bring fractures into sharper focus—especially when it comes to obtaining accurate permeability estimates from within shale gas formations. The operators who funded and shared field data for the project were ConocoPhillips, Hess, Shell, Equinor, Range Resources, and Apache. The other key participants included oilfield services firm Keane Group (recently renamed NextTier Oilfield Solutions) and a startup called ResFrac whose software was used to run the study’s models and numerical simulations. The group’s existence reflects both the rising value of pressure data in unconventional engineering and the struggles industry has in trusting it. The outcome of this yearlong study though hopes to improve upon the latter. The group has offered to the unconventional sector a new template for DFIT analysis, one that represents a distinct alternative to the classical methods used by most practitioners today. “We have a slightly different conceptual approach, and that impacts a lot of details. So it was necessary to basically start from scratch and make a new procedure,” said Mark McClure, a principal researcher in the industry study and the chief executive of ResFrac. The new procedure is the centerpiece of two technical papers recently shared at the Unconventional Resources Technology Conference (URTeC) in Denver, and the SPE’s Annual Technology Conference and Exhibition (ATCE) in•Calgary. Usually performed at the toe-end of a horizontal well, a DFIT involves pumping a small volume of fluid (typically 20•bbl or less) into the formation to induce a small fracture. How that fracture seals back up is then measured over a period that usually spans a 1–3 weeks. The test is used widely across shale plays to obtain estimates of rock stress, pore pressure, and, perhaps most importantly, permeability. It has become ubiquitous in the shale sector because it is an affordable way to quantify such properties before a pressure pumping crew arrives on a well pad. Additionally, where rock cores are susceptible to stress and permeability changes as they are brought to surface, the DFIT represents an in situ measurement that avoids these issues. However, the operator-led study asserts that the shale sector has misinterpreted the signals provided by a DFIT. The reason: accepted interpretation methods were largely designed for conventional reservoirs that feature far simpler physics than those that dominate tight-rock formations. The result: a systematic inflation of permeability estimates in gas shales and, to a lesser extent, inaccuracies in permeability estimates of oil shales.

URTeC returns to the Rockies — We came, we saw, we conquered

The fourth week of July 2019 saw 5200 oil and gas professionals descend on the Colorado Convention Center in Denver for the 7th annual Unconventional Resources Technology Conference (URTeC). Despite the fact that the exhibit floor was expanded this year, the high number of attendees meant the floor was clogged for much of the three-day conference, much to the delight of the companies and organizations exhibiting. As a historical note, this level of attendance is close to that of 2014, the second year of URTeC's existence and the second year it took place in Denver. I can assure our readers that a lot of people, from the organizing team to participating societies to exhibitors to companies involved in unconventionals, are happy (and relieved) to see this level of excitement and participation in this conference, given the fact that URTeC is rapidly solidifying its position as the go-to conference for unconventionals and a key barometer to gauge the health of the unconventional industry.

Shale Sector’s Switch to Slickwater Highlights Compatibility Issues with Produced Water

Switching from guar-based gels to slickwater fracturing fluids has delivered one of the biggest cost wins for the North American shale sector. First movers began the transition after guar prices spiked 300% in 2013. Shale producers have since reported they are trimming 20–35% from their completion chemical budget by using slickwater over the alternatives, while also reducing the pressure pumping power needed to move proppant into a tight reservoir. The replacement of gel treatments is possible thanks to the comparably low price of the key ingredient in slickwater recipes: polyacrylamide, or what some refer to as a high-viscosity friction reducer (HVFR). Beyond chemical savings, operators have experienced positive production results, too—adding fuel to the relatively quick adoption of slickwater treatments across every major play in North America. But since HVFR is a newly commoditized chemical with dozens of suppliers in North America and China, opera-tors are being advised to not let price be the sole deciding factor in which variety they pump downhole. A number of recent industry studies argue that aggressive screening is needed to make the right choice—especially if an operator is recycling or reusing produced water. “As a product, friction reducer can be different from company to company,” said Mohammed Ba Geri, a petroleum engineering PhD candidate at Missouri University of Science and Technology. “Most types work well with fresh water, but by increasing the salinity or changing the [total dissolved solids (TDS)] of the water, we see that everything changes.” Ba Geri spent more than 2 years running tests on about 30 different commercial friction reducers as part of a wider research effort that is chronicled in half a dozen SPE papers. He shared the latest of these at the recent Unconventional Resources Technology Conference (URTeC) in Denver. The variations in performance that Ba Geri cites, including in one of the papers he delivered at the conference (URTeC• 99), represent an important consideration given that more shale producers are shifting away from fresh water and toward using produced water for hydraulic fracturing. This development is being driven by a mix of regulatory, sustainability, and economic factors. By opting for produced water, distinguished by its high-salinity and TDS content, operators are essentially opting out of using linear or crosslink gels since they react so poorly to the lower-quality fluid. Per industry research, producers should also be careful in assuming this same risk is completely abated by taking the slickwater route. Friction reducers tend to hold up much better in a high-salinity and high-TDS environment. However, Ba Geri said that when the salinity or TDS rise above certain ranges, “all the polymer chains will break, and the viscosity and elasticity of that type of fluid will be less effective.” As the reaction takes place, globs of material will coagulate and reduce the ability of the friction reducer to carry proppant from the wellbore into the reservoir. Operationally, the effects can increase well costs quickly and reverse the advantages of using slickwater as stimulation rates drop, which in turn, would need to be offset with more pumping horsepower.

Huff ‘n’ Puff EOR Proves Effective in Gas-Condensate Reservoirs

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper URTEC-2019-987-MS, “Gas-Injection EOR in Eagle Ford Shale Gas-Condensate Reservoirs,” by Reza Ganjdanesh, SPE, Wei Yu, and Mauricio Xavier Fiallos, SPE, The University of Texas at Austin; Erich Kerr, SPE, EP Energy; Kamy Sepehrnoori, SPE, The University of Texas at Austin; and Raymond Ambrose, SPE, EP Energy, prepared for the 2019 Unconventional Resources Technology Conference, Denver, 22–24 July. The paper has not been peer•reviewed. Copyright 2019 Unconventional Resources Technology Conference. Reproduced by permission. As the pressure drops below the dewpoint in an unconventional gas-condensate reservoir, the liquid drops out of the gas phase and forms an oil phase in the matrix and fracture. The volume of the oil phase formed in the matrix mostly stays below the residual oil saturation. The gas huff ‘n’ puff process has demonstrated potential in improving recovery from tight oil reservoirs. The objective of the study described in this paper was to investigate the feasibility of huff ‘n’ puff enhanced oil recovery (EOR) in a•gas-condensate reservoir. Introduction Compositional analyses of fluid samples, taken from early production of three wells located a few miles apart from each other in Eagle Ford, were used to build the black-oil, volatile-oil, and gas-condensate fluid models. The produced field gas was selected as the only viable option for injection. Phase-Behavior Models The phase-behavior models were built for black-oil, volatile-oil, and gas-condensate wells on the basis of pressure/volume/temperature reports from bottomhole samples. The reservoir fluids were built by combining mathematically the oil and gas fluids from separators. The pseudocomponents were characterized from the detailed compositional laboratory analysis. The Peng-Robinson equation of state with the temperature-independent volume correction was used for phase-behavior modeling. The Lohrenz-Bray-Clark viscosity model was applied in calculating the phase viscosities. The condensate/gas ratio for the gas condensate fluid is 147 STB/MMscf, which is a rich gas-condensate fluid. Comparative Study of Gas Injection To compare the performance of huff ‘n’ puff gas injection in different fluid types, single-well simulation models were built for each fluid type. Several well models of 4,500 ft in length with a fracture spacing of 50 ft were built using a compositional simulator. The reservoir thickness was 130 ft. The hydraulic fractures were set up using the embedded discrete fracture model (EDFM) preprocessor. Each single-well model was history matched using the production data. Because the history-matching solutions were nonunique, the rate and pressure transient analysis for each well were used to limit the results to the realistic solution spaces. The history-matched fracture half-length varied between 50 and 175 ft and the fracture height varied between 50 and 90 ft. The fracture conductivity ranged between 3–30 md-ft. The history-matched models were used to investigate the performance of gas-injection EOR for all fluid types. The field gas was injected for 10 cycles, and the cumulative produced oil using huff ‘n’ puff was compared to one without gas injection. The incremental oil recovery for the nine studied black-oil cases varied between 30 and 40%. The incremental oil recovery was less than 10% for three volatile-cases and 15 to 20% for 13 gas-condensate ones.