SPE Papers Research Articles

President’s Column with Terry Palisch: The Value of Publishing Technical Papers for Your Career

_ This transcript is an excerpt from the podcast episode. Bryan: Hello, I’m Bryan Hibbard, senior editorial operations manager for SPE, I’m pleased to join 2024 President Terry Palisch as he continues his discussion about the ways we connect our members to technology by focusing on SPE papers, JPT, and other SPE publications. Terry, thank you for inviting me. Terry: Thank you for joining me, Bryan. I appreciate you taking the time to be the host. I thought you would make a good host for this topic. In December, I talked about regional sections and how I think that they are the face of SPE, and similarly when I think of reading and writing SPE papers or reading the Journal of Petroleum Technology (JPT), and the SPE Journal, these too are some of the key aspects of being an SPE member. It’s also front and center to our mission statement connecting our members to technology, serving as one of the primary ways we do that, and it also plays a role in connecting our members to other members. So, I thought it would be important to spend this episode talking about the importance of SPE papers, JPT, and continuing our focus on how members can get the most out of their SPE membership and in turn create their energy future. Bryan: SPE papers mean a lot to me. I manage the journals, as well as the conference papers at SPE. I know they are very special to you as well. When you and I did the How to Write a Good Abstract webinar together a couple of months ago, we got to hear a lot about your opinions on how to write a great abstract. So why do you think SPE papers are so important? Terry: Let me just tell you a quick story to illustrate the importance of papers. When I was a member of the Dallas Section several years ago, Danny Bell (SPE Dallas Section Education Chair) said his committee thought that writing papers was very important, so they asked me to put on a seminar on how to write SPE papers. That is what led to the webinar that you were just talking about. If you think about technical papers, engineers in all industries write technical papers, they do it to disseminate information and to memorialize their ideas and their discoveries. It is important to any profession that we write and document. When it comes to SPE I think papers are critical; without them we don’t have conferences or symposia. They enrich the multisociety library, OnePetro. In the end, it’s the way we disseminate technology and information to our members. But it’s also important to authors because they do the heavy lifting, they are the ones who do the writing, and sometimes they do it in their off time. More information about this is available from our webinar, mentioned earlier.

Technology Focus: Well Integrity (January 2024)

The context of last year’s Well Integrity Technology Focus was the repurposing of existing oil and gas wells for carbon storage, flow-wet material conformity, and associated integrity risks. Typically, oil and gas producing wells are abandoned toward the end of their life cycles with reservoir pressures depleted compared with the virgin pressures. Carbon capture and storage (CCS) projects, however, present different operating conditions. First, the pressurized containment sites have a higher life expectancy, say, between 50 and 100 years. Second, the containment pressure is possibly higher than the virgin pressure. The overpressure limit is dependent on several factors, especially the caprock sealing capacity. It goes without saying that CCS storage in wells requires long-term integrity (i.e., for the entire project life cycle). It is well-known that barriers such as cement and casings deteriorate over time. Deterioration of barriers may be accelerated by chemical reaction with carbon dioxide or thermal cycling. Hence, these storage sites could present unique life-cycle integrity risks perhaps never experienced by the oil and gas industry. To further explain the scenario, a possible breach of the confining strata resulting in pressure communication to the overburden means CO2 finding its way through the deteriorated well barriers of any active or shut-in well, resulting in CO2 ingress to the upper formations; groundwater contamination; or, in a worst-case scenario, appearance at the surface. Therefore, one of the important subsurface aspects of a CCS site is the presence of two seals (i.e., primary and secondary), with sealing capacity of both caprocks characterized robustly. Lack of double barriers or improper characterization of these confining strata could present a scenario wherein CO2 flows into overburden (i.e., above the caprock). The wells’ outer annuli then could become a potential path of least resistance for CO2 to migrate further up. Such situations can defy the primary objective of CCS projects and can require mitigation with proper attention to detail following the “as low as reasonably practicable,” or ALARP, principle. The scenario discussed is unique and complex and requires continuous managing and monitoring of CCS storage sites. Furthermore, the role of artificial intelligence and automation is seen as imperative during the operational stage of the project. In addition to the primary paper selections synopsized here, three SPE papers focusing on artificial intelligence and machine learning as tools for well integrity management are recommended as alternates for further reading. Recommended additional reading at OnePetro: www.onepetro.org. SPE 212479 Improve Well Integrity Using an Annular Barrier AI Tool by Eirik Time, Equinor, et al. SPE 211537 Transforming Production-Phase WIMS to a Game Changer Smart Well Integrity Monitoring System With Real-Time Automated Engineering Analytics by Mohammed Jasem, ADNOC, et al. SPE 216600 Paradigm Shift in Well Integrity Management Through the Use of Autonomous Wireless Well Intervention Robots by Julio Q.M. Guedes, Ouronova, et al.

Study Reviews Two Decades of Surveillance Using Distributed Acoustic Sensing

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 200088, “Downhole Monitoring Using Distributed Acoustic Sensing: Fundamentals and Two Decades of Deployment in Oil and Gas Industries,” by Mohammad Soroush and Mohammad Mohammadtabar, RGL Reservoir Management and University of Alberta, and Morteza Roostaei, RGL Reservoir Management, et al. The paper has not been peer reviewed. _ Distributed acoustic sensing (DAS) through fiber optics has been deployed in downhole monitoring for over 2 decades. The complete paper reviews the basics of DAS, fiber types, installation methods, types of recorded data, data processing, historical development, current applications, and limitations of the technology, providing a concise review using several field cases from more than 200 published SPE papers and journal databases. Because this synopsis cannot retain these many paper references or their overview, readers are encouraged to access the complete paper on OnePetro. DAS Fundamentals DAS Units. DAS systems consist of an interrogator that includes a laser transmitter and detector, a processing unit, and a distributed sensing fiber. Laser pulses are sent periodically into the fiber that is installed in the medium. The detector records backscattered response vs. time along the fiber. Because an acoustic field exerts pressure on the fiber it surrounds, some strain is induced on the fiber. An interrogator is sensitive to this strain between two points of fiber separated by gauge length. Multi- and Single-Mode Fibers. Generally, multimode fibers are used for distributed temperature sensing (DTS) and single-mode fibers are used for DAS. Multimode fibers have a larger-diameter core through which multiple modes of light can pass, while, in single mode, only one mode of light passes through the core. Attenuation in single-mode fiber is lower; therefore, single mode is suitable for long distances. On the other hand, multimode fiber can pass more data through the fiber and has higher attenuation. Data Type and Processing. Previous authors described how to reduce, convert, and transmit DAS recordings as data acquisition accumulates over time at the site without losing significant information. They also established three methods of data reviewing: local, remote display (from a remote server), and post-job integration (displaying all available data). A work flow of main steps for using DAS and DTS includes data gathering, auxiliary data, quality control and assurance, data management, and determination of interpretation options. Live data can be made available in permanent installations, while analytics libraries can be integrated into cloud-based DAS system. This will result in (nearly) real-time decision-making and easy-to-use forms of data. Multicomponent DAS. Because DAS systems are more sensitive in an axial direction, to estimate strain tensor, a multicomponent DAS was proposed with two approaches: multiple parallel or helix optical fiber. Another configuration was proposed with five helical fibers with equal space and one straight fiber for shorter wavelengths, addressing a limitation of previous methods.

Technology Focus: Drilling Automation and Innovation (February 2023)

With the arrival of the digital age, solutions in big data, automation, and artificial intelligence are rapidly opening the door to a deeper and more-comprehensive understanding of drilling operations around the world. The exponential growth in data acquisition, modeling, and prediction capabilities allows multiple drilling teams to identify hidden patterns and correlations to deal with the most-complicated challenges in well construction. In related SPE papers, it was interesting to read about promising initiatives undertaken by operators, service companies, and academia, not only to recognize details on past drilling events but also to accurately simulate, anticipate, and automate complex situations. Topics such as machine learning for improved decision-making, equipment-failure prediction, well placement lookahead, and autonomous operations have attracted great interest from the industry. Therefore, demand for a skilled workforce in digital technologies will continue to grow in drilling-related disciplines and new information and technology work flows will be incorporated into the well life cycle. As the active rig count continues to increase, safety must remain top priority for drilling operations. Advances in digital technologies and automation contribute to this objective while keeping a focus on cost management, operational consistency, and carbon-footprint reduction. Ongoing actions will also help to accelerate the development of geothermal energy as part of the future mix of renewables. The selected papers highlight some interesting contributions to drive innovation and promote efficient use of processes and technologies. Recommended additional reading at OnePetro: www.onepetro.org. SPE 205899 Measurements During Drilling Through an Innovative Microchip Technology To Determine Accurate Wellbore Properties for Efficient Drilling Operations by Zuyang Zhu, Sinopec, et al. SPE 211791 A Novel Real-Time Well-Collision Avoidance Monitoring by Definitive Dynamic Surveys and Passive Magnetic Ranging by Mahmoud ElGizawy, SLB, et al. SPE 210306 Drilling Heat Maps for Active Temperature Management in Geothermal Wells by Mohamed Shafik Khaled, The University of Texas at Austin, et al.

A systematic design approach for bulk gel treatments based on gel volume-concentration ratio in field projects

Controlling excessive water production in mature oil fields has always been a desired objective of the oil and gas industry. This objective calls for planning of more effective water-control gel treatments with optimized designs to obtain more attractive outcomes. Unfortunately, planning such effective treatments remains a dilemma for reservoir engineers due to the lack of methodical design tools in the industry.This paper presents a novel systematic design approach for polyacrylamide-based bulk gel treatments by classifying their field projects according to the gel volume-concentration ratio (VCR) into three design types. In terms of one another, the approach estimates either the gel volume or the gel concentration based on the average gel VCR of each design and formation type. First, field data was collected from SPE papers and reports of US Department of Energy for 65 gel projects conducted between 1985 and 2020. Stacked histograms were then used to examine distributions of field projects according to the gel VCR and the formation type. A comprehensive review of channeling strength indicators in field gel projects was performed to identify the classification criterion and design types of gel treatments. Based on the mean-per-group concept, the average gel VCR was assessed for each design type and formation type to build the design approach. Approximations for the overall gel concentration and correlations for extremum designs were established and included in the approach.The study showed that the gel VCR is a superior design criterion for in-situ forming bulk gel treatments. It aggregates gel treatments into three project groups and ranks them according to the channeling strength. The three project groups have clear separating VCR intervals (<1, 1–3, >3 bbl/ppm) and each of them is mostly dominated by one formation type. The VCR range of each project group represents one design type of the bulk gel treatments. The channeling type is the criterion of grouping and group-wise ranking of gel projects with respect to the gel VCR. In design type I, VCRs<1 bbl/ppm are used to treat pipe-like channeling usually exhibited by unconsolidated sandstones. More balanced VCRs of 1–3 bbl/ppm are designed for fracture-channeling frequently presented in naturally-fractured formations (design type II). Large gel treatments with VCR>3 bbl/ppm are performed to address matrix-channeling often shown in matrix-rock formations (design type III). Prediction results demonstrated that the VCR approach reasonably estimates volumes and concentrations of both single gel treatments and averaged field projects in training and validation samples. Besides its novelty, the new approach is systematic, accurate, practical, and will facilitate the optimization of future gel treatments to improve their performances and success rate.

Comments: Our Thanks and Best Wishes to You

As we wrap up 2022, I’d like to take this opportunity to thank you for your feedback and continued commitment to the JPT editorial team as we research and write our online and monthly articles, all exclusive to JPT. Your presentations at SPE conferences, technical papers, interviews, and contributed articles are what make this content the best in the industry. A special thank you goes to our Editorial Review Board. Here’s a sampling of JPT’s most-viewed features in 2022. - Think You Know Where Proppant Goes During Fracturing? Based on Recent Testing: Don’t Bet on It - Drillers vs. Granite: Hard Rock Is Losing Its Edge - CO2 Capture and Storage Requires Challenging Engineering in Unfamiliar Spaces - The Trend in Drilling Horizontal Wells Is Longer, Faster, Cheaper - Petroleum Engineering Continues To Drop, But There Is Talk of Better Times Ahead - What You Should Know About Offshore and Sour Gas CCS: High Cost, Leak Mitigation, and Transportation - Talos Eyes Big Carbon Capture Role in the US and Beyond - A Few Lessons From Tight-Rock Producers That Have Made Big Investments in Fracture Diagnostics - Water-Plus-Gas Injection on a Bakken Well Pad May Solve Problems That Stymied Shale EOR - The Fracturing Plan: Hit a Well 300 ft Away— How Hard Could That Be? - An Invention Promising Less Carbon and Cost Could Allow More Stranded-Gas Development - Is It Twilight for Deepwater US Gulf Megaprojects? - Big Fracs That Add More Oil May Also Mean More Water, and That Can Be All Right - The Produced Water Conundrum Grows Across Unconventionals As an SPE member, you gain access to the monthly edition of JPT on the 1st of each month (and archived issues at any time) by using your login and password. Each issue includes synopses of 12 OnePetro papers recently presented at conferences. You may download for free the SPE papers synopsized in that issue for 2 months. Be sure to take a look at each issue to spot papers of interest and download them. Beginning with the January issue, we’ll include a list of the SPE papers available for free download from JPT, including the previous and current issues, plus a preview of the technical topics to be highlighted in the next issue. These downloads from JPT are in addition to the 10 free downloads annually from OnePetro that are included in your membership benefits. You can also visit the HSE&amp;S discipline page to access a free download of a new featured HSE paper biweekly. To expand the delivery of content and provide added opportunities for networking and exchange of expertise and knowledge among members with similar technical interests, SPE launched four new technical sections in 2022: the Data Science &amp; Engineering Analytics Technical Section, Hydrogen Technical Section, Management Technical Section, and Methane Emissions Management Technical Section. Check out the full scope of technical sections here. The SPE Energy Stream was launched in January 2022. It’s your centralized source for live and on-demand video content about innovations, trends, and technical solutions. New content is frequently added. You’ll find a menu on the homepage that sorts content by upcoming live, trending, topic, product, Distinguished Lecturers, and SPE Event Highlights so you can go directly to what interests you. Sign up for the weekly SPE Energy Stream newsletter to catch the latest offerings. The JPT LinkedIn page, launched in September 2021, now has more than 6,100 followers. You’ll find content from JPT, OGF, HSE Now, DSDE, and TWA posted there. We wish you a happy holiday with time spent with your families and friends. Enjoy.

Technology Focus: History Matching and Forecasting (April 2022)

This year’s history matching and forecasting selections, made by reviewer Gopi Nalla of DeGolyer and MacNaughton, reflect the importance of accurate and innovative methodology in the approach toward development of unconventional or challenging plays, from tight oil to highly heterogeneous gas fields to coalbed methane. The authors of paper URTEC 208352 evaluate and compare the performance of rate-normalization and pressure-deconvolution techniques for both synthetic and tight-oil examples. While the synopsis is devoted mostly to the authors’ work in applying these techniques to synthetic cases, much of the complete paper is devoted to tight-oil examples. Ultimately, the authors recommend the pressure-deconvolution approach generally. In paper SPE 207933, the authors apply an integrated approach of using reservoir pressure/gas compressibility (P/Z) calculations to obtain a field gas initially in place (FGIIP) estimation that is then incorporated into an integrated asset model. The technique is applied to a giant onshore gas field. The authors conclude that the new FGIIP estimation can be applied as a reference to re-review the static modeling legacy and to narrow static modeling uncertainties, leading to reliable forecasting and more-efficient field development. An application of the iterative ensemble Kalman smoother to a scenario involving horizontal coalbed-methane wells for a low-permeability field in Australia is the subject of paper URTEC 208291. A forecast study was conducted to validate the history-matched ensemble, with the results showing a good match of 12 months of the new production data not used in history matching, highlighting the robust prediction capabilities of the presented approach. SPE papers continue to a be a vital resource for industry professionals; arguably, such work is more important than ever as the industry and the world adjusts to new modes of collaboration and realities in both the office and the field. I invite you to read the full text of these papers on OnePetro and to find further recent works that advance the literature of this specialized but critical Tech Focus topic. Recommended additional reading at OnePetro: www.onepetro.org. URTEC 208361 - Effect of Relative Permeability on Modeling of Shale Oil and Gas Production by Hamid Behmanesh, University of Calgary, et al. SPE 204835 - Successful Case Study of Machine-Learning Application To Streamline and Improve History-Matching Process for Complex Gas-Condensate Reservoirs in Hai Thach Field, Offshore Vietnam by Son Hoang, Bien Dong Petroleum Operating Company, et al. SPE 207855 - Unleashing the Potential of Relative Permeability Using Artificial Intelligence by Abdur Rahman Shah, Schlumberger, et al.

Technology Focus: Formation Evaluation (February 2022)

This marks the first of two Formation Evaluation features for 2022. The COVID-19 pandemic naturally has affected SPE meetings, causing many to be rescheduled or postponed indefinitely, but SPE papers continue to be a crucial source of technical knowledge. The selected papers explore simple and complex innovative approaches toward reservoir characterization to work around the absence of certain data. Paper SPE 203903 addresses issues related to safe and optimal operation of geoenergy applications related to induced seismicity as a result of pore-pressure fluctuations. The authors developed a finite-volume method with a multipoint approximation of fluxes for geomechanics and poromechanics that will cope with discontinuities in displacements, as occur in faults, on the level of discretization. The next paper demonstrates local calibration of a simple rock physics model that can provide valuable insights into the elastic properties, which then can be combined with seismic data for quantitative reservoir characterization away from the wellbore. The key, according to the author of paper OTC 30359, is the use of the Hashin-Shtrikman effective medium model with absolute upper and lower bounds for compressional and shear velocities of media that are composed of multiple constituents. The third paper explores the challenges of identifying and quantifying hydrocarbon sections because of little resistivity contrast between reservoirs and water zones in the absence of radioactive tools. The authors of paper SPE 202420 develop a work flow that integrates nuclear magnetic resonance with azimuthal resistivity to overcome the uncertainty of fluid typing and optimal wellbore placement. Despite the challenges our industry continues to face, authors of SPE conference papers continue to provide an important source of knowledge and experience. I hope you enjoy these papers and encourage you to visit OnePetro to find similar works that may deepen your interests and enhance your skills. Recommended additional reading at OnePetro: www.onepetro.org. SPE 203130 - Managing Sanding Risk in Sandstone Reservoir Through a New Constitutive Model by Surej Kumar Subbiah, Universiti Teknologi Malaysia and Schlumberger, et al. SPE 201672 - Estimating Reservoir and Fracture Properties From Stage-by-Stage Pressure-Decline Analysis in Horizontal Wells by HanYi Wang, The University of Texas at Austin, et al. SPE 202248 A Digital Core Laboratory Characterizing Oil/Water Transition Zones by Graeme Morrison, Woodside Energy

Technology Focus: Well Integrity (January 2022)

Almost every aspect of the upstream industry has been forced to adapt best practices and methodologies in significant ways over the last 2 years, and even the core discipline of assuring well integrity is no exception. Against a backdrop of global uncertainty and challenging economics, well integrity subject-matter experts have continued to prioritize human and environmental safety in production while pivoting their skills toward areas of growing importance such as carbon capture and sequestration. New technologies and simulation methods have allowed the authors of the three SPE papers in this year’s feature to provide a path forward that suggests new possibilities that retain the central goals of safety and productivity. Paper SPE 204385 describes the use of polymer capsules, embedded in cement and with semipermeable shells, that react with antagonistic gases downhole, such as carbon dioxide (CO2), to form a more-benign and -beneficial material. The author writes that, from this reaction with CO2, a mineral precipitate seals fractures in cement and aids in the recovery of wells. Part of the industry emphasis on decarbonization constitutes the repurposing of depleted fields as CO2 storage sites, as the authors of paper SPE 205537 describe in their discussion of such an effort offshore Sarawak. They use leakage-rate modeling to perform the critical task of estimating well integrity and re-entering existing plugged and abandoned wells. The authors of paper SPE 206052 explore various well-construction concepts and analyze the ability of cement to withstand long-term well loads. They write that, while reduction of cement stresses remains a challenge, one viable option is the use of cementless solutions, including a technology based on metal expandable packers that can seal long wellbore sections through metallic-to-rock isolation. No matter the specialized purpose or characteristics of any well, its integrity is the linchpin of production and safety. The SPE papers in this year’s feature display a versatility and willingness to tackle long-standing issues with new technologies and approaches that the upstream industry will always value. Recommended additional reading at OnePetro: www.onepetro.org. SPE 204374 - Epoxy Resin Exhibits Long-Term Durability and Chemical Stability as a Well Sealant by Fred Sabins, Riteks, et al. OTC 30299 - Big Data and Machine Learning: Effective Tools or Ensuring Well Integrity by Marcus Blane Savini, Frank’s International, et al. SPE 206252 - Development of a Digital Twin for Well Integrity Management in Underground Gas Storage Fields by Carlo Busollo, Snam, et al

The Changing Role of Education in the New Era of Energy

To say that the next generation of workers and leaders in our industry will be confronted by challenges unlike any we have known before is likely an understatement. For the foreseeable future, the list below provides a glimpse of what lies ahead. - An industry whose engineering and scientific foundation are still valid and necessary after 100 years but whose aversion to change has left it struggling to catch up in some areas, most notably in digital transformation (although significant progress has taken place in the past 18 months because of the pandemic) - The paradox of a world that will use fossil fuels to meet a large proportion of its energy demand for the foreseeable future while addressing the negative public and political perception of an industry tied to global climate change - Oil and gas companies morphing into “energy” companies, and petroleum engineers and geoscientists increasingly becoming known as “petrotechnical professionals” (PTPs) - The reality that petroleum engineering roles have expanded to straddle upstream, midstream, and downstream, whereas petroleum engineering programs are mostly geared to upstream and, more particularly, reservoir engineering - The replacement of Baby Boomers with Gen Zers who have an approach to work styles, life, and values generally different from the workforce they will need to lead This labyrinth of challenges, which is raising anxiety and questions about the future of petroleum engineering (PE) education, generated much interest and numerous ideas in the “Future Leaders’ Challenges and Educational Road Map” technical session at the 2021 SPE Annual Technical Conference and Exhibition (ATCE) in September. The papers in the session focused on what academia (and industry) can do to nurture the leaders of the future. A common thread was the need to enable students to not only sur-vive but also thrive as they transition into an evolving industry. The authors discussed issues they believe academia can control and govern—i.e., upgrading education and restructuring academic units—and issues such as demand changes, oil prices, and world politics that are beyond academia’s control. They also expressed agreement that certain elements within teaching and learning practices need periodic modifications—and sometimes serious paradigm shifts or even radical changes. Trends: What’s New (or Not) Paper SPE 205964 asked a rhetorical question, “Is it the end of an era or a new start?” Tayfun Babadagli, professor of petroleum engineering at the University of Alberta, pointed out that beginning with the first publication of an article on PE education in 1937, periodic reviews and evaluations—generally corresponding to industry downturns and drops in enrollment—have questioned whether PE programs should be removed from universities or restructured, depending on local conditions and industry needs. Following the 2014 crisis and a sharp decline in PE enrollments, several SPE papers suggested modernization options and changes in education that included options for local needs in certain geographic areas, field-based education, use of visual tools, and information technologies for smart wells and fields at a graduate (MSc) level. Inclusion of training in geothermal engineering was suggested in 2015. In the past couple of years, digital information sciences and new applications of PE sciences and subsurface storage and groundwater hydrology have been suggested.

Technology Focus: Formation Evaluation (August 2021)

Leading into the third quarter of this year, I am honored to be able to highlight and share three impactful SPE papers that demonstrate integration at its best. In reviewing the papers, five main technical themes emerged. These include * Machine learning and artificial intelligence as applied to formation evaluation * Production analysis methodologies and their effect on understanding rock characterization and behavior * Subsurface characterization primarily focused on rock typing and permeability * Tool advancements (openhole, cased-hole, or laboratory-based tools) * Subsurface-to-production integration across subdisciplines (e.g., geology, geochemistry, petrophysics, and engineering) The latter is the common thread between the three papers recommended and discussed here. In this new decade, the prevalence of integration is at the forefront of the scientific community. Every discipline, scientist, or company has a way in which they define the term “integration.” Regardless of how you define the effort that links disciplines quantitatively, the importance of constraining subsurface characterization to link it to production results and drive toward a predictive model is a critical accomplishment for our industry. As such, I’d like to highlight three papers in this feature (OTC 30644, SPE 201417, and SPE 202683) and the knowledge and workflow applications they define and demonstrate. Sharing these integrated work flows with the community aids in teaching and leads to best-practice components of integrative studies. These efforts also share and demonstrate how to bridge the gap between in-situ characterization and wellhead performance prediction and results—in other words, the static-to-dynamic link between rock and fluid properties as quantified and how they will inevitably produce hydrocarbon through the rock and fluid interactions. Recommended additional reading at OnePetro: www.onepetro.org. SPE 201334 Combined Experimental and Well-Log Evaluation of Anisotropic Mechanical Properties of Shales: An Application to Wellbore Stability in the Bakken Formation by Saeed Rafieepour, The University of Tulsa, et al. SPE 201486 A New Safe and Cost-Effective Approach to Large-Scale Formation Testing by Fluid Injection on a Wireline Formation Tester by Christopher Michael Jones, Halliburton, et al. SPE 201735 Integrated Reservoir Characterization With Spectroscopy, Dielectric, and Nuclear Magnetic Resonance T1-T2 Maps in a Freshwater Environment: Case Studies From Alaska by ZhanGuo Shi, Schlumberger, et al.

Technology Focus: Subsea Systems (August 2021)

Flow assurance in subsea oil and gas fields often presents significant challenges. Every field has its own combination of difficulties, and no universal process or system can be used to mitigate these. Detailed knowledge across a broad range of competencies, therefore, is required to find solutions that can minimize the risk of not getting the hydrocarbons safely to the process facilities. Many subsea fields that are being developed today are long tiebacks, taking advantage of existing offshore infrastructure or producing directly to shore. These developments must deal with the long-distance transport of hydrocarbons in deep cold water, commonly increasing the risk of hydrate formation and wax deposition, for example. In addition, large elevation changes from deep water to surface and topographical challenges along the pipeline can create flow-regime effects that can hinder production. The loss of temperature in a long subsea pipeline also creates challenges for fields that produce heavy oil because the oil viscosity in some cases increases dramatically at low temperatures, in addition to effective viscosities increasing because of oil and water emulsions. Other phenomena such as scale deposition, foaming, sand production, erosion, and corrosion must be considered and dealt with as well. Various smart-technology innovations for subsea oil and gas production contribute to reducing the risk of these flow-assurance issues. Some of them are described in this month’s selected SPE papers. A good example is as follows: When wells start to produce water, the operator needs to understand where the water is coming from and quantify volumes in order to start a mitigation program to avoid hydrate formation. This is one of the reasons why subsea multiphase flowmeters have become an essential feature in all new subsea fields. The most common remedy for flow-assurance problems is probably the use of chemical additives. A sensor technology that can directly determine the ratio between produced water and chemicals such as monoethylene glycol has been recently introduced in subsea production systems. This measurement enables the optimization of chemical-injection rates, thereby contributing to significant savings in capital expenditure (reduced design margins) and operational expenditure (reduced overdosage margins). Another effective way to prevent hydrates and wax is to keep the process temperature above critical limits by applying active flowline heating. New technologies for highly reliable and efficient subsea electrically heat-traced flowlines have recently been qualified, industrialized, and installed. Technologies as described here can play an important role in future subsea field developments. The recommended readings for this feature date back further back in time than usual, but are relevant to the theme of this year’s main selections. Recommended additional reading at OnePetro: www.onepetro.org. OTC 29232 Real-Time Subsea Hydrate Management in the World’s Longest Subsea Tieback by Christophe Vielliard, OneSubsea, a Schlumberger Company, et al. OTC 31078 Electrically Heated Trace Flowline on the Ærfugl Project—A Journey From Product Qualification to Offshore Campaign by Guy Mencarelli, Subsea 7, et al. SPE 195784 A New Flow-Assurance Strategy for the Vega Asset: Managing Hydrate and Integrity Risks on a Long Multiphase Flowline of a Norwegian Subsea Asset by Stephan Hatscher, Wintershall Norge, et al.

Technology Focus: Decarbonization (July 2021)

Have you noticed the change in the oil and gas industry over the past year with its engagement in carbon management, decarbonization, and net-zero-emissions targets? Policy support and technology advances in alternative energies have delivered massive cost reduction in renewables more quickly, and to a greater degree, than expected. Over the past few years, more of the world’s capital has been spent on electricity than oil and gas sup-ply, and more than half of all new energy-generation capacity is now renewable. Some elements of society, therefore, have suggested that this is the beginning of the end for the fossil-fuel sector and call for investors to turn away from oil and gas and “leave it in the ground.” In more than a century of almost continuous change, however, the oil and gas industry has a long track record of innovative thinking, creative solutions, and different business models. SPE papers and events that covered decarbonization during the past year show that a wide variety of solutions already exist that avoid, reduce, replace, offset, or sequester greenhouse gas (GHG) emissions. It is clear, therefore, that decarbonization technologies will now be as important as 4D seismic, horizontal wells, and hydraulic fracturing. That is why we now bring you this inaugural Technology Focus feature dedicated to decarbonization. The experience and capability of the entire JPT community in decarbonization is critical. Please enjoy the following summary of three selected papers on the role of natural gas in fuel-switching; carbon capture, use, and storage (CCUS); and hydrogen technologies that deliver the dual challenge of providing more energy with less GHG emission. There are many ways to engage in the SPE decarbonization efforts in the remainder of 2021. Regional events have addressed CCUS, hydrogen, geothermal, and methane. There is also the new SPE Gaia sustainability program to enable and empower all members who wish to engage in the alignment of the future of energy with sustainable development. The Gaia program has an on-demand library of materials, including an existing series on methane, and upcoming similar events on other energy transition, natural capital and regeneration, and social responsibility priorities. Get involved through your SPE section or chapter or contact your regional Gaia liaison to find out what Gaia programming you can support or lead at www.spe.org/en/gaia.

Will This Be the Decade of Full Digital Twins for Well Construction?

The time needed to eliminate complications and accidents accounts for 20–25% of total well construction time, according to a 2020 SPE paper (SPE 200740). The same paper notes that digital twins have proven to be a key enabler in improving sustainability during well construction, shrinking the carbon footprint by reducing overall drilling time and encouraging and bringing confidence to contactless advisory and collaboration. The paper also points out the potential application of digital twins to activities such as geothermal drilling. Advanced data analytics and machine learning (ML) potentially can reduce engineering hours up to 70% during field development, according to Boston Consulting Group. Increased field automation, remote operations, sensor costs, digital twins, machine learning, and improved computational speed are responsible. It is no surprise, then, that digital twins are taking on a greater sense of urgency for operators, service companies, and drilling contractors working to improve asset and enterprise safety, productivity, and performance management. For 2021, digital twins appear among the oil and gas industry’s top 10 digital spending priorities. DNV GL said in its Technology Outlook 2030 that this could be the decade when cloud computing and advanced simulation see virtual system testing, virtual/augmented reality, and machine learning progressively merge into full digital twins that combine data analytics, real-time, and near-real-time data for installations, subsurface geology, and reservoirs to bring about significant advancements in upstream asset performance, safety, and profitability. The biggest challenges to these advancements, according to the firm, will be establishing confidence in the data and computational models that a digital twin uses and user organizations’ readiness to work with and evolve alongside the digital twin. JPT looked at publications from inside and outside the upstream industry and at several recent SPE papers to get a snapshot of where the industry stands regarding uptake of digital twins in well construction and how the technology is affecting operations and outcomes. Why Digital Twins Gartner Information defines a digital twin as a digital representation of a real-world entity or system. “The implementation of a digital twin,” Gartner writes, “is an encapsulated software object or model that mirrors a unique physical object, process, organization, person or other abstraction.” Data from multiple digital twins can be aggregated for a composite view across several real-world entities and their related processes. In upstream oil and gas, digital twins focus on the well—and, ultimately, the field—and its lifecycle. Unlike a digital simulation, which produces scenarios based on what could happen in the physical world but whose scenarios may not be actionable, a digital twin represents actual events from the physical world, making it possible to visualize and understand real-life scenarios to make better decisions. Digital well construction twins can pertain to single assets or processes and to the reservoir/subsurface or the surface. Ultimately, when process and asset sub-twins are connected, the result is an integrated digital twin of the entire asset or well. Massive sensor technology and the ability to store and handle huge amounts of data from the asset will enable the full digital twin to age throughout the life-cycle of the asset, along with the asset itself (Fig. 1).

Technology Focus: Digital Data Acquisition (January 2021)

COVID-19 has significantly accelerated the adoption of digital technologies across all industries, and the oil and gas industry has been no exception. Consequently, interest in digital data acquisition, the backbone of all digital transformation work flows, also has increased significantly. This can clearly be seen in the multifold increase in the number of SPE papers on this topic since last year. This feature will continue to focus on technologies to improve data accessibility and data acquisition, as well as entirely new data sources and their applications. The papers chosen this year include real-time remote monitoring of steam traps and corrosion using wireless sensors, enabling faster and easier access to relevant subsurface information through deep learning of unstructured documents, and automation of real-time drilling work flows through digital transformation technologies. While not reflected in these papers, a related emerging technology that has the potential to transform the data acquisition paradigm and that is garnering much attention, however, is edge computing. As the saying goes, if you cannot bring the data to the model, take the model to the data. One of the main difficulties in faster adoption of digital transformation in oil and gas has been access to reliable real-time data that can be converted to real-time decisions. This is the case because of the remote and geographically distributed nature of most oil and gas assets and legacy outdated and piecemeal information-technology (IT) infrastructures, making it difficult to provide models with reliable, standardized data in a timely manner. Edge-computing frameworks eliminate scale and capacity constraints and bypass limitations of current IT infrastructures, truly enabling operationalization of models for real-time decision making. Edge computing, together with machine learning and artificial intelligence, will be the real enablers of digital transformation.

Technology Focus: Drilling Innovation (February 2020)

Technology Focus Summer jobs working on drilling rigs in western Oklahoma and California in 1980 and ’81 were great adventures. High oil and gas demand meant major and independent operators used some of the latest, state-of-the-art rigs to probe deep into high-pressure reservoirs. Planning and executing wells back then was a manual process with experience, horsepower, pencil, and calculator. My adventures continued after I graduated from college in 1982. Ever-evolving drilling, completion, and subsurface technology characterized the years that followed. Fast forward to February 2020. “The more things change, the more they stay the same,” the old-timers might say. In many field locations today, old-school machinery and processes remain in place. However, we see artificial intelligence (AI), data analytics, machine learning, and related advancements transforming our industry. These developments have been headlines for several years now but will take more time to reach full fruition. Experts agree this is just the beginning. Jensen Huang, chief executive officer and founder of Nvidia, highlighted this during a CNBC interview in November. “We are at the beginning of the AI revolution, one of the most powerful technological forces of all time,” he said. “We’ve created the ability for computers to understand the code of human knowledge. All industries will be transformed.” Huang, an AI visionary, showed a 4D simulation of an unmanned Mars landing craft on final approach going from 12,000 mph to zero in 6 minutes. Such visionaries are also working in upstream exploration and production to achieve remarkable advancements. A focus on drilling innovation reveals no shortage of SPE papers that exemplify these exciting trends. Without exception, the featured articles reflect increased volumes of surface and downhole data that are being captured and analyzed to enable deep learning, improved efficiency, safety, and value. As noted in paper OTC 29487, oil and gas companies are creating layers of digital knowledge enabling a new generation of AI-driven applications. New insights into mitigation of drillstring vibration, well-control events, and rate-of-penetration optimization follow. Managed-pressure drilling remains a persistent trend that continues to evolve across onshore, offshore, and geographical boundaries, opening new frontiers once seen as out of reach. One need not look to outer space to imagine the extent of breakthroughs to come in the not-too-distant future. Recommended additional reading at OnePetro: www.onepetro.org. SPE/IADC 194535 Nitrogen-Cap Drilling: A Managed-Pressure-Drilling Alternative for Highly Fractured Carbonate Reservoirs by Alexey Podust, Tengizchevroil, et al. SPE 196166 Standardization: Successful Implementation of Driving Consistency in Deepwater Operations by Daniel A. Durey, Shell, et al. SPE 197942 Innovative Digital Well-Construction-Planning Solution Enhances Coherency and Efficiency of the Drilling-Design Process by Waldemar Szemat-Vielma, Schlumberger, et al.

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.

Technology Focus: Unconventional Resources (July 2019)

Technology Focus The charge of a JPT Technology Focus reviewer is not only to select the best SPE papers encountered over the past year but also to identify potential ways in which these papers, and the technology contained therein, can assist the growth of industry professionals. While all of JPT’s feature topics are of great importance to the industry, the technical attention and economic importance attached to unconventional plays in recent years stresses a need for appropriately unconventional thinking. For this year’s feature, the selected papers provide innovative work flows that assist in determining productivity, reduce the effect of uncertainty conditions, and spark rejuvenation. The first of these, paper SPE 190860, emphasizes the importance of an effective lateral-landing strategy in enhancing long-term reservoir productivity and provides a work flow that uses a suite of integrated data to achieve consistent results that can aid in field management and ultimate recovery estimates. Paper SPE 191272 uses a case study from the Vaca Muerta Shale in Argentina to demonstrate the efficacy of a work flow that uses a simulation-based approach combined with high-speed computing to improve investor confidence. The authors stress in particular the need to characterize the correct variables and to establish the range of their uncertainty. Finally, paper SPE 191457 introduces an integrated work flow that couples geomechanical effects and reservoir-simulation modeling in the effort to rejuvenate unconventional plays, stressing interpretation of the variables that can affect the development of the simulated reservoir volume. These three innovative papers represent, as always, the skill and vision of industry professionals like yourself as we continue to learn from, and add to, the body of technical knowledge that SPE represents. I hope that you enjoy the papers. Recommended additional reading at OnePetro: www.onepetro.org . SPE 191923 Alleviating the Solids Issue in Surat Basin in Coal-Seam-Gas Wells by Daniel Kalinin, Schlumberger, et al. SPE 192010 Optimizing Horizontal Coal-Seam-Gas Wells by Combining Reservoir Simulation and Transient Well Modeling by Turaj Nuralishahi, APLNG, et al. SPE 192694 First Global Successful Large-Diameter Pressurized Coring Application Using High-Performance Water-Based Mud: Kuwait Case History by Robin Stewart, Halliburton, et al.

Technology Focus: Seismic

Technology Focus Last year saw continued contraction in the seismic data-acquisition industry. This included both onshore and offshore operations. Most notably, WesternGeco exited land and marine data acquisition. (In the case of marine, WesternGeco sold all of its vessels, facilities, and technologies to Shearwater GeoServices.) Ironically, it was just 1 year ago when I discussed in this column the new and exciting acquisition-related advances in the industry that had been developed for the purpose of better data sampling. With this drop in acquisition business, it is not surprising that there were fewer seismic data-acquisition papers published in SPE proceedings. Nevertheless, several excellent SPE papers covered important acquisition and processing topics. One of the papers deals with the current state of the art for addressing marine challenges. This is described with a 3D case history from the Gulf of Thailand. Another paper deals with leading-edge techniques that were used in a recent onshore 3D survey in Abu Dhabi. And a third paper showcases the application of a relatively new technology, distributed acoustic sensing (DAS). DAS is rapidly finding a home in vertical-seismic-profile surveys and in unconventional programs. Indeed, this third paper deals with a DAS study performed in the Marcellus Shale. Offsetting the drop in the number of acquisition papers was a proportionate increase in the number of SPE papers that covered other important seismic topics. These included inversion and reservoir characterization, 4D interpretation, seismic for carbonate plays, and machine learning. (Similar to what is happening in other industries, machine learning is receiving tremendous attention now in the seismic world.) Though industry fluctuations may affect our areas of specialty, there will always be room for improvement driven by innovation. Recommended additional reading at OnePetro: www.onepetro.org. SPE 189888 Seismic Attributes Application for the Distributed Acoustic Sensing Data for the Marcellus Shale: New Insights to Cross-Stage Flow Communication by Payam Kavousi Ghahfarokhi, West Virginia University, et al. SPE 192948 How Broadband, High-Density, Full-Azimuth, and Point-Source Point-Receiver Acquisition Improves Seismic Interpretation in Onshore Abu Dhabi by Sheikha Al-Naqbi, ADNOC Onshore, et al. SPE 192956 Comparing Seismic Inversion Methods on a Carbonate Reservoir: A Case Study From the Mishrif Reservoir, Rumaila Field, Iraq by Olabode Joseph Olatoke, BP, et al. SPE 192927 Effect of Seismic Acquisition and Processing Techniques in Challenging Subsurface Imaging, Block G11/48, Gulf of Thailand by Phansakorn Kaewprain, Mubadala

A Review of Field Oil-Production Response of Injection-Well Gel Treatments

SummaryAs life-span extenders, bulk gels have been widely applied to rejuvenate oil production from uneconomic producers in mature oil fields by improving the sweep efficiency of improved-oil-recovery (IOR)/enhanced-oil-recovery (EOR) floods. This paper presents a comprehensive review of the responses of injection-well gel treatments implemented between 1985 and 2014. The survey includes 61 field projects compiled from SPE papers and US Department of Energy reports. Seven parameters related to the oil-production response were evaluated according to the reservoir lithology, formation type, and recovery process, using univariate analysis and stacked histograms. The interquartile-range (IQR) method was used to detect the underperforming and overperforming gel projects. Scatterplots were used to identify the effects of the injected-gel volume and the treatment timing on the treatment response. Pretreatment water cut, recovery factor, and flood life were used as indicators for the treatment timing.Results indicated that gel treatments have very wide ranges of response for injection and production wells and for oil and water rates and profiles. When successfully applied, they, on average, respond after 3.5 months, increase the oil-production rate by 32%, and additionally recover 116,000 STBO per treatment, 15 STBO per gel barrel, or 10 STBO per polymer pound. We identified that gel treatments perform more efficiently in carbonate (CB) than in sandstone (SS) reservoirs and in naturally fractured (NF) formations than in other formation types. In addition, the incremental oil production considerably increases with the channeling strength and the injected-gel volume for all formation types, not just for the matrix-rock (MR) reservoirs. Moreover, gel treatments applied in NF formations have lower productivities in SS than in CB reservoirs using normalized performance parameters.Declining trends were identified for all parameters of the oil-production response with the treatment-timing indicators. The sooner the gel treatment is applied, the faster the response, and the larger the incremental oil production and its rate. It is recommended to allow longer evaluation times for gel treatments applied in MR formations because their response times might extend to several months. Gel treatments will perform more efficiently if they are conducted at water cuts of less than 70%, flood lives of fewer than 20 years, or recovery factors of less than 35%. For different application environments, the present review provides reservoir engineers with updated ideas regarding the low, typical, and high performances of gel treatments when successfully applied, as well as how other treatment aspects affect performance.