Frac Hits Research Articles

Integration Analysis of 3d Fractures Network Reconstruction and Frac Hits Response in Shale Wells

Integration Analysis of 3d Fractures Network Reconstruction and Frac Hits Response in Shale Wells

What Is Really Happening When Parent and Child Wells Interact?

When trying to understand the well-to-well events known as frac hits and fracture-driven interactions (FDIs), the first idea to embrace is this: they are not all the same. “And the key physical mechanisms are not the same,” said Mark McClure, who added that, “Until you’ve really dialed in on what those are, you’re really in the dark.” McClure is the cofounder and CEO of ResFrac Corp. In March, the modeling firm began a multiclient study to diagnose the relationships between parent and child wells—or what many consider to be the ultimate subsurface challenge facing the shale sector. Participating operators are Marathon Oil, Hess Corp., Pioneer Resources, Arc Resources, Birchcliff Energy, SM Energy, and Ovintiv Inc. These independent E&Ps represent a cross section of some of the most active plays in North America: the Midland and Delaware basins and the Bakken and Montney shales. But what makes the study unique, McClure said, is that it involves 10 rich data sets from well pads that were subjected to a number of cross-validating diagnostics: tracers, pressure/interference monitoring, geochemistry, and fiber optics. ResFrac has been using that data to calibrate its coupled reservoir-fracture models to see what knobs clients might want to turn in the future to improve well economics. The study is also trying to unearth some firm answers about what is really happening during offset stimulations, why it is happening, and what can be done to mitigate negative outcomes. ResFrac and its clients expect to wrap up this part of the study by the year’s end and to submit an abstract for an SPE technical conference in 2022. As the study nears an end, McClure offered some of his key observations that he noted are supported by previous research found within industry literature. So, What’s the Worst That Can Happen? A growing chorus of subsurface experts consider unwanted chemical reactions in the fracture network as one of the major damage mechanisms resulting from FDIs. McClure is not only among them, he said chemical effects represent the “worst” that can happen when parents and children interact. “This is where you see wells get hit, they lose 80% of their production, and it doesn’t come back,” he explained. Some in the industry have taken to calling the byproduct of these chemical reactions “shmoo” or “gunk.” For answers as to why this is happening, McClure points to two technical papers in particular.

Machine-Learning Work Flow Identifies Brittle, Fracable, Producible Rock Using Drilling Data

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 201456, “Machine-Learning Work Flow To Identify Brittle, Fracable, and Producible Rock in Horizontal Wells Using Surface Drilling Data,” by Ngoc Lam Tran, SPE, Ishank Gupta, SPE, and Deepak Devegowda, SPE, University of Oklahoma, et al., prepared for the 2020 SPE Annual Technical Conference and Exhibition, originally scheduled to be held in Denver, Colorado, 5–7 October. The paper has not been peer reviewed. The complete paper demonstrates the application of an interpretable machine-learning work flow using surface drilling data to identify fracable, brittle, and productive rock intervals along horizontal laterals in the Marcellus shale. The results are supported by a thorough model-agnostic interpretation of the input/output relationships to make the model explainable to users. The methodology described here can be generalized to real-time processing of surface drilling data for optimal landing of laterals, placing of fracture stages, optimizing production, and minimizing frac hits. Modeling Approach In a multiwell field development, the ability to improve recovery efficiency per rock volume depends on well spacing, stacking, completion strategy, and avoidance of frac hits. In this study, the authors use surface drilling data to predict mechanical rock facies (generated using Poisson’s ratio and Young’s modulus) using several supervised classification methods. The objective is to use the trained model to predict the mechanical facies in real time using surface drilling data in future wells to optimize the well trajectory and placement of fracture stages. The highlighted modeling approach is conducted as follows: - Data preparation. Preliminary univariate (histograms, box plots) and bivariate analyses (cross plots) are performed, outliers removed, and missing values handled. The clean data are scaled, and a few additional derived variables such as mechanical specific energy (MSE) are added (also called feature engineering) that may boost predictive efficiency. - Unsupervised clustering. Clusters are generated using the derived variables of Young’s modulus and Poisson’s ratio. The number of clusters is optimized by silhouette width and within the sum of squares. The clusters group points of similar brittleness/fracability and are referred to as a geomechanical facies in this paper. - Supervised classification. A classifier is built using K-nearest neighbors, gradient boosting, random forests, and neural networks to identify geomechanical facies from surface drilling data. Seventy-five percent of the data are used for training and 25% for testing. Tenfold cross validation is performed on the training data to prevent overfitting. In 10-fold cross validation, the training data is subdivided randomly into 10 parts. The model is trained on nine parts and then validated on the remaining part. This process is repeated multiple times for each machine-learning technique. Only those models are averaged to provide the final model that gives good results for the validation data.

ConocoPhillips’ Water-Hammer Analysis Highlights Potential for a Complex Dataset

It has often amounted to little more than background noise. Now, engineers with one of the largest shale producers in the US consider the water-hammer signal to represent a potential trove of insight into stimulation performance. ConocoPhillips has spent almost 3 years developing a new approach to water-hammer analysis and recently shared the first public details of that work in a technical paper (SPE 204154). Perhaps the core takeaway is that within a few minutes of post-stage data, a picture of reservoir and stimulation quality is available. The challenge lies in how to bring that picture into proper focus. The water hammer is a pressure pulse that moves through the wellbore at the speed of sound in fluid, or around 5,000 ft/s, which is more than four-fold the speed of sound in air. Its name comes from the often-audible slam made on one end of the pipe when a column of moving fluid is slowed or halted. One is usually generated as a valve is turned, or a pump slowed or stopped at the end of a fracture stage. This makes the water hammer ubiquitous in the context of hydraulic-fracturing operations the world over. As the wave bounces up and down the wellbore it generates noticeable pressure spikes on wellhead gauges. These oscillating signatures have been the subject of industry intrigue for decades. They’ve also proven to be difficult to decipher and trust. As such, the water hammer has not entered into the shale sector’s pantheon of fracture-design inputs. ConocoPhillips’ ongoing research and development project may help change that. Based on a review of treatment data from more than 150 of the operator’s low-permeability wells from an unnamed field in North America, those with fast-decaying water-hammer signals amounted to the best performers, achieving an output equivalent to 94–110% of their estimated recoveries. On the other hand, wells with more prolonged or low decay rates commonly fell 10–20% below their original type curve. “The high decay rates indicated more near-wellbore fracture surface area, which related to higher well productivity. While conversely, low decay rates mean less near-wellbore friction, longer fractures, lower well productivity,” explained Dung “Zoom” Nguyen. Nguyen is a staff completions engineer at ConocoPhillips and coauthor of the paper that she presented at the annual SPE Hydraulic Fracturing Technology Conference in May. She elaborated that analysis on frac hits, or fracture-driven interactions (FDIs), supports the relationship between fracture geometry and water-hammer decay rates, i.e., low decay rates equate to fewer, longer, and less-complex fractures.

Optimal Spacing of the Wolfcamp in the Delaware Basin

Proper well spacing for horizontal wells is one of the missing pieces for the Delaware Basin development in the Wolfcamp Formation. In the Wolfcamp formation in the Delaware Basin, well spacing varies with formation characteristics (rock and fluid) across the Basin. Finding the spacing intervals between horizontal wells right is crucial to maximizing productivity and estimated ultimate recovery (EUR) while avoiding detrimental frac hits and cross-well pressure and fluid interference during stimulation and production.

Implementation Challenges of Extended Reach Drilling and Hydraulic Fracturing Operations in Unconventional Reservoirs

The petroleum industry faces a lot of challenges in producing hydrocarbons. These challenges became significant with the discovery of unconventional reservoirs. This called for new advanced technologies to be developed. Extended Reach Drilling (ERD) and Hydraulic Fracturing (HF) are two methods that were successfully implemented in different wells around the world. ERD has been used in numerous drilling operations where the reservoir is surrounded by troublesome formations, hence sidetracking is necessary. Hydraulic fracturing is used in the development of many unconventional wells, including shale gas reservoirs. However, these methods still face a lot of challenges during implementation, which can affect the success of the drilling and well completion design. This article discusses the main design considerations for implementing ERD and Hydraulic fracturing in an unconventional reservoir. It also covers the main challenges that should be accounted for while preparing the drilling and well stimulation design to improve the production efficiency. It includes the impact of stress shadows, frac hits, well spacing, casing design, and other factors on the overall success of the process.

Precise Interlateral Spacing for Optimal Stimulation and Enhanced Production in North American Shale

Summary The growing problem of well-to-well fracture interactions in North American shale plays dictates the need for more accurate interlateral spacing measurements. Conventional wellbore surveying techniques, such as magnetic and gyroscopic measurements while drilling (MWD), cannot guarantee optimal placement due to growing systematic errors that dominate survey uncertainty. This uncertainty may impede optimal field stimulation modeling because the wellbore positioning data used in the analytical calculations are inaccurate. Multiple industry technical papers demonstrate a correlation between interlateral spacing and the severity of frac hits. The interlateral distance measurements are used in the calculations for optimal reservoir stimulation and frac hit modeling. With present commodity prices, the industry cannot afford suboptimal field development caused by inaccurate well placement. In this paper, we compare the conventional survey technique with a commercially proven long-distance active magnetic ranging system that supplements the traditional MWD system. We apply relevant survey error models to two exemplary well pads—an actual well pad from a West Texas shale play and a realistic, although hypothetical, example—and compare them with relative ranging uncertainty. The first example shows that MWD positional error exceeds relative ranging uncertainty while the wells are still near vertical at approximately 6,500 ft measured depth (MD). The second example shows that interlateral spacing uncertainty using active magnetic ranging can be 50% of the MWD semimajor error at the end of the curve at 10,000 ft MD [8,910 ft true vertical depth (TVD)] before the lateral section starts. The MWD uncertainty then gets larger due to systematic survey errors multiplied in the “dead reckoning” computation process. With the magnetic ranging applied while drilling, the ranging uncertainty stays practically the same throughout the whole well, enabling tenfold improvement in interlateral spacing accuracy.

An Unconventional Challenge Can Casing Failures During Hydraulic Fracturing Be Stopped?

Shale producers around the world have learned in recent years that they cannot take wellbore integrity for granted. During pressure-pumping treatments, the interplay of hydraulic fracturing and formation geomechanics is deforming and even shearing steel casing. In the worst of cases, this means that some operators have lost access to long sections of a wellbore before it produces a single barrel of oil. This is largely not viewed as an inter-well challenge similar to frac hits. Rather, it is considered to be intrawell phenomena. The problem can take several forms and has no universal driver. George King, an independent consultant and leading technical voice on hydraulic fracturing, points out that not every unconventional asset is affected—indicating that geology and understanding of the rock fabric matter. However, information he has collected from client operators shows that in certain US shale and tight oil fields, between 20%–30% of horizontal wells are impacted to some degree. “Sometimes it is with the cement support, and sometimes it is with the casing itself,” said King, listing two of the problem’s general root causes. He added that the casing deformation is “an artifact of some damage that we are seeing right now in the realm of fracturing, and [during] the time period of fracturing.” A commonly reported version of the problem emerges after just a few stages at the toe-end of a horizontal well have been fractured. As another plug is pumped downhole to continue the completion, it suddenly stops 1,000 ft to 5,000 ft short of its target. This could happen in the bend, or it could be somewhere deep in the lateral. Often the deformation is described as ovalling. If a restriction consumes much more than a tenth of an inch of the pipe’s original internal diameter, there is the potential that unstimulated stages beyond the stopping point are lost to conventional plug-and-perf methods. This fate can sometimes be avoided by running slim-profile perforating guns, but then other isolation technologies are still needed to replace conventional plugs. Unconventional operators in China, Argentina, Canada, and the US have all faced the issue. In response, the technical community has recently stepped up collaboration efforts at industry conferences to find answers. In China, the issue appears to be more widespread on a per-well basis. National oil companies working the Sichuan Basin, the country’s most active unconventional area, have reported that more than 40% of gas wells have experienced casing deformation or failures. Like their US counterparts, Chinese operators typically realize the problem during a post-fracturing tool run. Argentina’s Vaca Muerta is not immune either. A 2015 technical paper coauthored by researchers at Chevron and YPF (URTeC 178620) casts casing shear and restrictions as common and “extremely detrimental to the performance of the well.” When explaining why the issue is cropping up today, more than a decade into the shale revolution, experts are quick to point out that a lot has changed since the first horizontally drilled and hydraulically fractured wells.

To “Right Size” Fractures, Producers Adopt Robust Monitoring and Custom Completions

As the shale sector looks for ways to improve well results, momentum is building to take a much closer look at how and where hydraulic fractures are created while pressure pumping fluids into tight, complex reservoirs. The effort is being driven by unresolved questions over optimal well spacing and fracturing techniques. They are two closely related issues that dovetail into sector-wide production shortfalls associated to frac hits, a common well-to-well effect that experts in the technical community have recently named fracture-driven interactions. One of the biggest challenges in overcoming these issues is to learn how to control the size of hydraulic fractures (the general emphasis is on reducing their lateral and vertical extensions) with a far finer degree of accuracy and finesse than is realistic today. There is an expanding array of diagnostic studies and new technologies working to this end. Several of the latest examples were highlighted at the recent Unconventional Resources Technology Conference (URTeC) in Denver. Operators both large and small used the conference as an opportunity to express support for the broader use of tools considered to be classic components of petroleum and reservoir engineering: wellhead and bottomhole pressure gauges. These two technological cousins are nothing new to the oil field, but have only recently become viewed as essential among those seeking affordable answers about how their fractures behave during the treatment. “The industry badly needs a low-cost, stage-by-stage method that we can use for assessing the reservoir quality, the completion design, and fracture complexities,” said Michael Sullivan, a reservoir diagnostics advisor with Chevron, during a technical session at URTeC. “Unfortunately, the high-cost and operational complexity is a barrier to most other stage-level assessments. What we need is something we can afford to do.” Sullivan was presenting a paper (URTeC 970) that describes how Chevron’s Canadian asset team in the Duvernay Shale recently began using “free” wellhead pressure data to estimate each fracturing stage’s performance. His hope is that others follow the workflows as Chevron looks at more than half-a-dozen ways to use the data (including perforation cluster efficiency analysis and frac hit identification) to refine its completions approach. Sullivan highlighted that the new learnings are thanks to pressure gauges it uses per standard procedure, meaning they are on wellheads whether the data is analyzed or not. To drive down costs further, Sullivan advised other operators to buy their own gauges vs. renting them from service companies. “What I’ve been emphasizing around our company is that this is a measurement we can afford to make—so let’s make sure we’re getting the most out of it,” he•added.

Physics-guided neural networks for predicting unconventional well performance — using Unconventional Rate Transient Analysis for smarter production data analytics

Geoscience modelling poses many challenges due to the limited sampling and the complexity of the phenomena that create the resulting rock and its properties. When adding to the geologic and geomechanical complexity the various possible fluid flow mechanisms that are often not fully understood, one realizes quickly how daunting geomodelling could be. As a result, oil and gas fields are often bought and sold using reserves computed with simple decline curve analysis tools. Unfortunately, these simplified production analysis tools contain no physics and do not help develop oil and gas assets which require the knowledge of 1) rock properties distribution and 2) the impact of the rock properties on the selected production mechanism. For example, if one has a naturally fractured reservoir, the presence or absence of the natural fractures and the way the wells are drilled to encounter or avoid these rock properties will determine the reserves and the future of the company developing such an asset. Very often the future of many companies is not very bright due to their lack of knowledge of the distribution of the rock properties such as natural fractures and the subsequent fluid flow resulting from drilling and fracking into these heterogeneous rock properties. For the companies that want to prosper by intelligently developing their assets, niche companies and technologies have been used throughout the years to address all these challenges. Among these technologies we find the use of artificial intelligence and machine learning, which were introduced in the oil and gas industry in the early 1990s with successful application to petrophysics, well test analysis and reservoir modelling. Three decades later, the oil industry and its unconventional revolution is facing frequent challenges ranging from frac hits and well interferences, casing deformation and collapses, expensive cube development with meagre returns on investment and many other puzzling issues with no easy solution. Suddenly, under the stress of financial constraints, the machine learning tools criticized for three decades as ‘black boxes’ are now becoming the preferred solution to all problems. Unfortunately, this love-hate relationship the oil industry has with data-driven approaches may hit a rough patch very soon due to its inability to recognize the limitations of the available data used in the various oil and gas challenges.

Investigating Hydraulic Fracturing Complexity in Naturally Fractured Rock Masses Using Fully Coupled Multiscale Numerical Modeling

Naturally fractured rock mass is highly inhomogeneous and contains geological discontinuities at various length scales. Hydraulic fracture stimulation in such a medium could result in complex fracture systems instead of simple planar fractures. In this study, we carried out fully coupled multiscale numerical analysis to investigate some key coupled processes of fluid-driven fracture propagation in naturally fractured rock mass. The numerical analysis follows the concept of the synthetic rock mass (SRM) method initially developed in the discrete element method (DEM). We introduce a total of five case study examples, including fracture initiation and near wellbore tortuosity, hydraulic fracture interaction with natural fractures, multi-stage hydraulic fracturing with discrete fracture network (DFN), in-fill well fracturing and frac hits after depletion-induced stress change, and induced seismicity associated with fault reactivation. Through those case studies, we demonstrate that with an advanced numerical modeling tool, the complex fracturing associated with hydraulic fracturing in naturally fractured rock mass can be qualitatively analyzed and the extent of various uncertainties can be assessed.

E&P Notes (May 2019)

PTTEP to Buy Murphy Oil’s Malaysian Business for $2.1 Billion Matt Zborowski, Technology Editor Thailand’s PTT Exploration and Production (PTTEP) is doubling down on Malaysian oil and gas in an effort to broaden its reach in its native South-east Asia. PTTEP has agreed to acquire Murphy Oil’s Malaysian business for $2.1 billion in an all-cash deal. PTTEP also announced that it was awarded two Malaysian exploration blocks in the Malaysia 2018 bid round. The assets to be purchased produced 48,000 BOE/D net to Murphy last year, of which 62% were liquids, and consisted of proved reserves of 468 Bcf of natural gas and 51 million bbl of liquids. The deal includes five petroleum exploration and production projects—Sabah K, SK309 and SK311, Sabah H, SK314A, and SK405B—in the shallow and deep waters off the Malaysian states of Sarawak and Sabah. Global Oilfield Services Market Won’t Recover Until 2025 Trent Jacobs, JPT Digital Editor It has been a tough few years for the world’s oilfield service sector and, according to a new report, the best of times are on hold for a few more. This is according to Rystad Energy, which says the sector is on pace to capture $920 billion in revenue by 2025. The Norwegian market research firm has highlighted the figure as the high-water mark reached in 2014, a year that ended with crude prices falling by more than 40%. “This will be the longest slump faced by the oilfield service industry since the 1980s, with about $2.3 trillion in revenues lost along the way,” said Audun Martinsen, Rystad Energy’s head of oilfield service research. Martinsen continued by noting: “On the bright side, in only 3 years’ time, activity levels will be higher than they were in 2014, although the cost cuts achieved in the sector means spending levels will only be 80% of what was seen in that peak year.” ExxonMobil, Chevron Target Nearly 2 Million BOE/D in Permian Production Matt Zborowski, Technology Editor ExxonMobil and Chevron revealed plans that would result in combined production from the US majors of nearly 2 million BOE/D from the Permian Basin of West Texas and southeastern New Mexico by the mid-2020s. ExxonMobil revised upward its Permian production outlook by almost 80% to reach 1 million BOE/D by as early as 2024. The operator said its resource base in the basin totals 10 billion BOE. Chevron expects its output from the basin to rise to 600,000 BOE/D by year-end 2020 before hitting 900,000 BOE/D by yearend 2023. The company said it has added some 7 billion BOE in Permian resources over the last 2 years. Shale Pioneer: Hard Ceiling On Production Growth Coming Trent Jacobs, JPT Digital Editor The central debate today in the US shale business is how long productivity growth will continue. According to one of the most influential voices in the sector, the answer is not much longer. “I am not particularly optimistic that, over the next 5 years, the industry is going to be able to show the year-over-year improvements in well recoveries that we’ve seen over the past 10 years,” said Mark Papa, chief executive officer of private-equity-backed shale producer Centennial Development Resources. Papa said the two biggest factors at play are frac hits, or parent-child well interference, and a shrinking inventory of high-quality drilling locations. Shale CEO on Parent-Child Challenge, Well Declines: We Know Matt Zborowski, Technology Editor Much has been made recently about the disparities in production between parent and child wells in US shale basins. The increased attention on the issue is part of broader concern among investors about the ability of operators to maintain high levels of output over the next few years. However, Doug Suttles, Encana president and chief executive officer, assures that shale executives are acutely aware of the parent-child challenge. His company has been “very public about this for 5 years now,” he said before an audience largely consisting of the investor community at CERAWeek by IHS Markit this week in Houston. He ultimately doesn’t think it’s “a big threat” to the shale sector. ExxonMobil Makes Huge Gas Discovery Offshore Cyprus ExxonMobil has made what it says is the world’s third-largest natural gas discovery in 2 years off the coast of Cyprus in the eastern Mediterranean Sea. Based on preliminary interpretation of the well data, the discovery could represent an in-place natural gas resource of up to 8 Tcf. The Glaucus-1 well, located in Eastern Mediterranean Block 10, encountered a gas-bearing reservoir of approximately 436 ft. The well was safely drilled to a depth of 13,780 ft in 6,769 ft of water. Industry consultants Wood Mackenzie told Reuters news agency that it estimated recoverable resources of Exxon’s field to be 4.55 Tcf. That compares with its 6.4 Tcf estimate for Calypso, found by Italy’s ENI and France’s Total last year.

To Solve Frac Hits, Unconventional Engineering Must Revolve Around Them

Hydraulic fracturing as it is now executed in North American shale plays may have to be replaced with a much more intricate scheme—one that better matches the complex fabric of tight reservoirs. The impetus for an engineering overhaul is being forced by the prevalent well-to-well fracture interactions known as frac hits. These events are the subject of intensifying study by US and Canadian shale producers that have attributed them to lowering oil recovery factors from new child wells by 20–40% while inflicting even higher losses on older, yet less productive, parent wells. How the industry manages the impact of frac hits going forward is likely to define its future growth rate. “They’re not going away—we’re only going to be drilling more and more child wells,” said Brendan Elliot, a senior completions engineer with Devon Energy, as he advised a large gathering of petrotechnical colleagues that they need to “quantify the risk” of frac hits as early as possible in order to know what to do next. Elliot provided a rare look into how a large shale operator is dealing with the problem during the opening session of SPE’s Hydraulic Fracturing Technology Conference (HFTC) held recently in The Woodlands, Texas. His outline highlighted the extent to which the Oklahoma City-based producer is revolving its infill development programs around frac hits. “The things you really want to look at are where the positive and negative events are occurring,” he explained while showing an analysis program that Devon has spent the past couple of years building to visualize those outcomes. The tool, which analyzes data from more than 2,000 frac hit events, has led the company to realize that what determines whether a frac hit will benefit or hurt production comes down to time and production volumes. While this relationship was not a new learning, Devon has quantified it to 10 months and 100,000 bbl. Once both limits have been surpassed, the expectation is that frac hits will have negative consequences on pad production. Elliot elaborated on how this trend is acted upon using the company’s three-pronged approach. Its component pieces include the design of infill wells, addressing reservoir depletion through pressure management (e.g., repressurizing tactics), and then zooming out to adjust the wider field development program. The sum of these parts is a new playbook for unconventional completions, one that stands in stark contrast to the “cookie cutter” designs that gave rise to the shale revolution. Its methodical approach to decision making is aimed at gaining control over fracture growth and maximizing production from child wells. This can be done by adjusting fluid rates in a single well scenario, or altering an entire field development plan based on the risk that frac hits pose. In just a few slides, Elliot succinctly linked together years of accumulated knowledge into a workflow that could feasibly be replicated by other companies struggling with the sector’s most pressing reservoir management issue. “These full-life cycle workflows—don’t get me wrong—these will be lengthy processes, and large projects, so we need to improve as an industry,” cautioned Elliot. “Every mitigation strategy has a risk, it’s going to be specific to each reservoir, it’s going to be variable in the black oil window and your volatile gas window, and you really must cater to the asset value and the value to protect [the resource] in place.”

Comments: Shale’s Second Act

Editor's column Another industry report issued last month touts the coming gains in US shale, predicting that the country will soon be the largest oil producer and possibly exporter in the world. The International Energy Agency’s (IEA) Oil 2019, a 5-year outlook on the global energy industry, touts the “second wave” of the shale sector, which will transform oil markets worldwide. The IEA says the US will lead the way in oil supply growth over the next 5 years because of continued growth in shale, primarily from the Permian Basin. By the end of that 5-year period, the US will surpass Russia and be close to Saudi Arabia in total oil exports. Although consumption from China will decline and the use of electric vehicles will grow, demand will be stronger for jet fuel and petrochemicals, leading to an annual global increase of 1.2 million B/D. US oil output will account for almost three-fourths of the supply increase over the period, growing a total of 4.4 million B/D, following a production increase of 2.2 million B/D in 2018. “The second wave of the US shale revolution is coming,” IEA Executive Director Fatih Birol said in releasing the report. US oil output, including natural gas liquids, will rise to 19.6 million B/D by 2024. Excluding liquids, oil production will increase from the current 11 million B/D to 13.7 million B/D. One transformation taking place in the US shale sector is the entry of majors. Independents have dominated the play so far, led by such companies as Pioneer and Apache. But the short-cycle production time and geopolitical safety is increasingly attracting interest from large firms such as ExxonMobil, Chevron, and ConocoPhillips. ExxonMobil and Chevron announced plans last month to increase spending even more in the Permian Basin over the next few years. Although the industry has consistently underestimated US shale growth, some producers and engineers have a more nuanced outlook for the sector. There are potential hurdles to overcome if shale is going to continue to be the star in the global supply picture. Steep decline curves, parent-child well interference (or frac hits), and perhaps even a lower inventory of high-quality drilling locations are concerns. The issue of frac hits dominated discussion at the recent SPE Hydraulic Fracturing Technology Conference. Parent-child well interactions may be lowering oil recovery factors from new child wells by 20–40% while also causing losses on older, yet less productive, parent wells, according to US and Canadian operators. That has led Mark Papa, one of the pioneers in US shale and chief executive officer of Centennial Development Resources, to become less optimistic about the future of US shale production. Frac hits and fewer high-quality drilling options may force a lower ceiling on shale, undermining these optimistic forecasts, which leads him to believe that the shale sector is already in its mature phase of producibility, he said during a panel discussion at the IHS Markit CERAWeek conference in Houston last month. But panelist Greg Powers, vice president of global innovation at Halliburton, cautioned that most of the learnings from shale to date have been experiential, not fundamental, and that a lot of the resource is still in the ground. In addition, he said, the chemistry of hydraulic fracturing is still a bit of a mystery. In other words, there is still much to figure out before concluding whether shale’s second act is its final one.

Preventing frac hits and well interferences with fast marching simulation using embedded discrete fracture models constrained by poroelastic geomechanical modelling of enhanced permeability

Investors are not happy. A recent article by a major newspaper (Olson et al., 2019) again highlighted the issue of ‘underperforming’ unconventional wells’ production targets. It notes that financial executives from the oil industry state that predicting well performance is an art rather than a science. Others involved in the management of billions of shale assets offer their opinion by noticing that ‘Geology doesn’t line up with Excel spreadsheets too well, unfortunately.’ These sentiments reflect the perceived state of unconventionals’ technology which is reduced to ‘an art and relying on Excel spreadsheets’. Such comments have dramatic consequences on all stakeholders in the unconventional business. A serious consequence came about shortly after the newspaper article was published: a law firm started an investigation targeting executives of an oil company accused of misleading their investors by providing them with false well performance forecasts. Lawyers and financiers quarreling about such highly technical matters put the burden on scientists and engineers to bring practical solutions to this complex problem. During this decade, great efforts have been made to better understand the performance of unconventional wells, but the challenges are overwhelming, and they evolve as our understanding of hydraulic fracturing progresses. Chief among these challenges, we find the issue of frac hits and well interferences.

Guest Editorial: Unlocking Unconventional Reservoirs With Data Analytics, Machine Learning, and Artificial Intelligence

Guest editorial The concept of the digital oil field has been around for many years and the industry is beginning to experience the benefits of data analytics, machine learning, and artificial intelligence (AI). The upside of digital technology is it can improve operational efficiencies and reduce costs. The downside of digitization is that many companies have neither the resources nor the expertise to collect, analyze, and interpret a critical mass of data while maximizing its economic return. Predictive Behavior for Unconventional Reservoirs As North America shale plays are once again becoming economically viable, operators in all major basins have fast-adopted best practices to optimize drilling and completion processes to drive down the lifting costs. Adoption of data-driven analytics to improve completion design, drive efficiency, and yield economic gains has been less swift. In years past, an operator would perform analysis on a single well completion and make decisions using publicly and privately available data, well logs, or sometimes nothing more than experience gained through the years. As the industry moves to more complex multipad, multiwell completion designs, intelligent completion optimization will require more sophisticated algorithms to improve decision making. The question remains as to how operators can use the vast amount of data readily available in the public domain and private data to develop and train models that enable them to realize these operational efficiencies and increase estimated ultimate recoveries. This is where the use of analytics and AI can directly drive efficiencies to unlock the production potential of unconventional reservoirs specifically during hydraulic fracturing. The growing volume and availability of completion and production public data creates a revolutionary situation in which pad planning and completion design becomes possible with pure AI methods. Benefits of AI-Driven Analysis There are two main avenues where digital technologies are expected to make the largest impact: automation and optimization. With predictive analysis, the industry will be able to automate and optimize the process of completion design to mitigate completion disfunctions such as frac hits or uneven cluster performance. The inputs can come from quality data curated from wellsite records that include cluster spacing, pressure and rates, volumes pumped, fluids and sands used, diversion and flowback practices, production data, borehole assemblies, analyzed offset data, geology data, the plan of the well itself, and the offset wells that set up the pad development plan. The most desired improvement of including AI into completion design is speed of the entire analysis and modeling process. The trained AI system does 6 to 8 weeks of manual research in seconds, identifying specific design hazards buried within amassed pages of completion and production reports. This accelerated tempo ultimately leads to reduction of nonproductive time. Numerous completion parameters can be changed or improved using computational intelligence and mathematical optimization including stimulation volume, fluid types, flow rate, well later-al and cluster spacing, as well as numerous other considerations. Optimization on these parameters must always be done coupled with economics. Long- or short-term goals will steer decisions to different completion designs. For example, with economics taken into account, the objective of avoiding frac hits at all cost may not be necessary. A trained AI model that predicts type curve and optimizes the cost function provided by economic objectives could discern that a certain level of risk of frac hits is acceptable and even beneficial.

Fighting Water With Water: How Engineers are Turning the Tides on Frac Hits

Frac hits were once a painful cost of doing business for Abraxas Petroleum. But today, the San Antonio, Texas-based shale producer has softened the blows dealt by this widespread and challenging problem. Its approach, called “active well defense,” has been put to the test amid the rolling hills of the company’s North Fork oil field in McKenzie, North Dakota. “Necessity is the mother of invention—and that’s our story here,” said Peter Bommer, vice president of engineering at Abraxas, who noted that the driver of its strategy was not production declines, as it has been for others. Instead, active well defense is designed to prevent temporary, yet costly, production stoppages caused by unabated frac hits filling parent wells with sand. The company starts by injecting produced water at low pressures into older, parent wells. It flows down miles of wellbore and into the formation’s partially depleted fracture networks where it has proven to prevent the damage often caused by high-pressure hydraulic fracturing of new child wells—known as frac hits. Active well defense relies on sporadic injections to reinforce the preloaded water. To do this, Abraxas has partnered with a technology vendor Abra Controls, whose custom communications network gives engineers “real-time pressure monitoring so we can watch the wellhead pressures in the parents, and when we start to see interference, we start pushing back on it,” Bommer said. Active well defense is now used across Abraxas’ infill program in its 3,300-acre development targeting the Bakken and Three Forks shale plays. Its genesis and evolution are covered in two technical papers, the latest of which was published at the start of the year (SPE 184851 and SPE 189860). Renewed Trend Examples of similar strategies have recently emerged from other major North American plays. They include BHP Billiton’s “preloads” in the Eagle Ford Shale of Texas and Canbriam Energy’s “pump-ins” in the Montney Shale of Alberta. Similar tactics are being tested in the Permian Basin and the Anadarko Basin. This trend sits on one side of the well-defense spectrum, while on the other are the more capital-intensive projects known as cube developments that drill and complete a dozen or more wells in quick succession to avoid the downsides of reservoir depletion. Published results on injection-based well defense are encouraging, but it remains unclear whether they will scale up to stem concerns over the shale sector’s ability to sustain record output in the face of falling productivity of new child wells. These operations are distinct from refracturing, as both Abraxas and BHP emphasize that the injections use pressures that do not open new fractures, or affect existing ones much. Injection-based defense is not stopping frac hits, said Marcus Bayne, a fracturing supervisor with Abraxas. “But if we can interfere with the interference, then we can have the fluid we’re injecting act as a shock absorber, or a diffuser, so we don’t push solid material into the parent wellbore.”

Three Unconventional Startups Offer New Clues on Shale’s Biggest Well Spacing Mysteries

It can be fairly argued that the most important question being asked today by shale producers is: How close can horizontal wells be placed together? The right answer is worth billions of dollars to the sector. Among the unsolved mysteries with well spacing are how and why hydraulic fractures from neighboring wells interact with each other. These events, described as frac hits, can be beneficial to oil production (as has been documented in the Bakken Shale) but the more pressing concern is focused on the cases where they harm production (often the case in the Permian Basin and Eagle Ford Shale). Petroleum engineers know that production-depleted zones within their reservoirs play a big role, but predicting the effects this has on their well designs will require completely new diagnostic approaches. To solve this grand challenge, an increasing number of industry startups have put their technologies, ones originally developed with a different purpose in mind, under the microscope. The clues they have discovered so far could reshape how the industry understands highly complex shale plays—where profits and losses can be decided by landing a well 100 ft in one direction or the other. These young companies are among those coming up with some of the most compelling pieces to the puzzle. Fracture ID invented a measurement-while-drilling tool that can detect depleted reservoir sections; Reveal Energy Services has a monitoring system that may be able to diagnose interwell fracture activity; and ResFrac Corp. is using its new modeling software to help operators better estimate permeability, which ties right into well spacing and fracture cluster design. Can You Measure Depletion While Drilling? Founded in 2014, Fracture ID offers a new service called “drill bit geomechanics” that could become an early warning system for frac hits caused by pressure and hydrocarbon depletion from older producing wells. The wellbore-focused service has been used by more than three dozen operators to improve on several different aspects of completion efficiency, including helping to make sure proppant effectively moves into perforations. While a lot of its work is focused on what is happening around the wellbore, over the course of its 350-well track record the company has determined, “what we’re measuring in the near-field has some extension out into the farfield,” said Chris Neale, the chief executive officer and founder of Fracture ID. He explained that the downhole data the firm gathers during drilling show correlations to the pressures that operators monitor during and after stimulating a fracture stage. This relationship is seen as one key to predicting which stages will most likely lead to fracture interference. At the core of Fracture ID’s service is a foot-long accelerometer device that sits behind a drill bit and enables the Denver-based firm to translate drilling vibrations into critical rock descriptions, including stress and strain, two performance-driving factors for completions.

In the Battle Against Frac Hits, Shale Producers Go to New Extremes

A new plan has been put to work in the Permian Basin’s remote but resource-rich swath of land shared by Texas and New Mexico. Its objective can be reduced to this simple idea: protect neighboring horizontal wells from each other by drilling and completing them at the same time. Most in the shale business know these projects as “cube developments.” Their scope of work has moved operators away from developing wells one at a time to a half dozen or more at a time. Each cube project is done from supersized well pads that host four to six rigs, two pressure pumping fleets, and hundreds of people every day. From the surface perspective, these onshore megaprojects are delivering much needed economies of scale on everything from sand and water to parts and labor. However, the bigger motivation lies deep in the ground. That is where shale producers have been battling poor production results for years because of frac hits between older and newer wells, often referred to as “parent” and “child” wells. The root of this complex problem lies in the fact that a child well’s hydraulic fractures often follow the path of least resistance into a reservoir’s most resource-depleted zones, rather than to areas containing the best reserves. In some parts of the Permian, the effect has caused child wells to deliver a 30% lower recovery rate than their parents (when factors such as well lengths are normalized). When such production shortfalls are felt fieldwide, the losses are measured in millions of dollars per day. The point of cube developments is to put an end to this cycle by creating only parent wells. Thinking Inside the Cube Occidental Petroleum began implementing its own version of the cube approach—called “optimized sequenced development”—last summer at its Greater Sand Dunes project in New Mexico. This year, the Permian stalwart says new wells brought on line there have turned in “basin-leading” peak 30-day rates that averaged around 3,100 BOE/D. The Houston-based firm’s approach relies on a strong understanding of geomechanics to sequence the drilling, completion, and eventual flowback of multiple wells to mitigate frac hits. This allows some wells to be produced, while others nearby are still being drilled or hydraulically fractured, said Oscar Quintero, the president and general manager of Oxy’s Permian assets in New Mexico. If done correctly, and critical rock properties are entered into the equation, then “you have vertical isolation, and you have horizontal isolation” of each well’s hydraulic fracture growth, said Quintero. “So, by design, we are avoiding the impact of frac hits.” This succinct outline of the high-density approach boils down a long list of subsurface nuances, ones that remain an intense area of study for the shale sector. Understanding them helps explain why Oxy and a growing number of its peers would go to the lengths of drilling so many wells simultaneously.

Using surface drilling data for a geologically and geomechanically constrained 3D planar frac simulator and fast reservoir simulation — application to engineered completions and well interference prevention

Modelling unconventional reservoirs requires increasingly complex physics to describe the phenomena that affect the performance and efficiency of horizontal wells. For example, poroelastic geomechanical simulation (Ouenes et al., 2017b) is needed to model frac hits and well interferences resulting from the presence of stress and pressure dependent natural fractures and other geologic factors that see their permeability increase during stimulation. Recent field observations related to stress relaxation required the introduction of viscoelasticity (Peterson et al., 2018) to better understand the effect of timing during fracing. Lastly, the importance of interfaces and their impact on fracture height growth required the introduction of 3D damage mechanics (Aimene et al., 2018) to model the propagation of hydraulic fractures in a more realistic rock volume that considers the layering of the various lithologies and the resulting weak interfaces that will in turn interact with hydraulic fractures. This increasing complexity in physics is also combined with the need to provide solutions very quickly, if not in real time As the physics of unconventional reservoirs becomes more complex, the data available at each well to correctly model that physics is dwindling at an alarming rate. The introduction of the continuum multiscale approach (Ouenes et al., 2017b) and the use of surface drilling data provide the unique opportunity to address both the lack of data and the increasingly complex physics. In the absence of wireline logs and seismic data, surface drilling data collected at each well is used at different scales ranging from wellbore to reservoir scale. In this process called ‘Inverse Design and Validation’, the information contained in the surface drilling data is used 1) during the drilling to optimize the landing zone and geosteering, 2) during the design of the completion to geoengineer the stages to account for the variability of the rock, and 3) to build 3D models that will allow the correct estimation of petrophysical, geomechanical properties and stresses needed in 3D planar frac simulators as well as fluid flow simulation. These various applications are examined in the next sections.