Journal of Petroleum Technology最新文献

{"title":"Reservoir Modeling Predicts Effect of Cold-Water Injection on Geothermal PTA","authors":"C. Carpenter","doi":"10.2118/0224-0069-jpt","DOIUrl":"https://doi.org/10.2118/0224-0069-jpt","url":null,"abstract":"\u0000 \u0000 This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 212615, “Reservoir Modeling To Predict the Effect of Cold-Water Injection in Geothermal Pressure Transient Analysis,” by Purnayan Mitra, SPE, University of Petroleum and Energy Studies, and Nihal Mounir Darraj, SPE, Imperial College London. The paper has not been peer reviewed.\u0000 \u0000 \u0000 \u0000 Geothermal reservoirs are one of the cleanest renewable sources of energy poised to address the global energy challenge. A major issue in the exploitation of geothermal reservoirs, however, is to find best-fit analytical methods for pressure transient analysis (PTA). This is because the assumptions made to predict PTA in hydrocarbon reservoirs are not satisfied by geothermal reservoirs. In the complete paper, the effect of cold-water injection on PTA of geothermal reservoirs is studied by varying the temperature of the injected cold water from room temperature to reservoir temperature.\u0000 \u0000 \u0000 \u0000 A major method of extracting heat energy from the Earth is the injection of water. Cold water is injected deep into geothermal reservoirs at a depth of 2–4.5 km. In this environment, cold water is essentially heated by the hot granite rock. Hydraulic fracturing is used to produce a large crack within the geothermal reservoir. Two boreholes intercept the crack. These boreholes are used for passing the cold fluid stream and the hot stream, respectively. In many scenarios, the gradient within the geothermal reservoir is so strong that a dry stream is produced. The greater the temperature difference between the injected fluid and the interior of the Earth, the greater the heat transfer. Therefore, it is always desirable to inject cold water inside geothermal reservoirs to maximize heat transfer and extract more heat. The steam coming out from the reservoir after heat transfer is used to run turbines to generate electricity. The steam also is used for a variety of other purposes. However, instances exist in which the temperature gradient is not as high, and it is difficult to produce a sufficiently heated dry stream. In such cases, an organic Rankine cycle is used for heating the steam on the surface. In such a case, the hot water or steam mixture is passed through a heat exchanger for heating the fluid to a desired temperature.\u0000 When cold water is injected into the reservoir, a need exists to analyze the pressure transience throughout the reservoir. Different formations affect PTA in different ways. PTA across the geothermal reservoir currently is performed using the empirical correlations available for hydrocarbon reservoirs. Although the method is not 100% effective because of differences in reservoir parameters, PTA provides an idea about reservoir conditions. To reduce imperfection, it is often preferred to use reservoir parameters rather than injectate properties. In the complete paper, the authors study the effect of injected water on geothermal reservoirs while varying temper","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2024-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139886953","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Approach to Perforation Interval Selection Uses AI-Assisted Image Interpretation","authors":"C. Carpenter","doi":"10.2118/0224-0078-jpt","DOIUrl":"https://doi.org/10.2118/0224-0078-jpt","url":null,"abstract":"\u0000 \u0000 This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 216856, “ML-Driven Integrated Approach for Perforation Interval Selection Based on Advanced Borehole-Image AI-Assisted Interpretation,” by Alexander Petrov, SPE, Mounir Belouahchia, SPE, and Abdelwahab Noufal, SPE, ADNOC. The paper has not been peer reviewed.\u0000 \u0000 \u0000 \u0000 In the complete paper, the authors propose an artificial-intelligence (AI)-assisted work flow that uses machine-learning (ML) techniques to identify sweet spots in carbonate reservoirs. This process involves annotation of geologic features using a well database, with supervision from subject-matter experts (SMEs). The resulting ML model is tested on new wells and can identify pay zones, perforation intervals, and stress analysis. The models successfully detect fractures, breakouts, bedding planes, vugs, and slippage passages with pixel-level precision, reducing borehole-image (BHI) analysis time.\u0000 \u0000 \u0000 \u0000 The use of BHIs requires manual interpretation and data identification, heavily relying on the expertise and time of SMEs. A widely adopted approach to address this challenge is the use of supervised computer-vision algorithms, a subfield of AI. These algorithms optimize the task function or model based on examples they have learned from data during training. However, when applied to BHIs, certain ML challenges must be addressed, including the following:\u0000 - Detecting features in wells from different reservoirs using a model trained on wells from one reservoir can be highly challenging because reservoirs may exhibit distinct geological characteristics.\u0000 - The handling of parts of BHIs with missing data, depicted by vertically slanted white strips, poses considerable difficulty. Therefore, the authors created a deep-learning approach based on a generative adversarial network architecture to fill the gaps automatically (Fig. 1).\u0000 - The labels provided by geologists often do not have pixelwise precision, causing the machine to become confused while trying to learn inconsistent patterns.\u0000 The authors use a convolutional neural network (CNN) to compute a probability map for pixels belonging to specific classes. In this application, a class is defined as any of the heterogeneities in the BHI; however, this method is applicable to any type of heterogeneities in an image. After training, the CNN module provides the optimal probability for each pixel in the image.\u0000 To classify regions in the BHI based on heterogeneities, a class-specific threshold is established. Pixels with values above the thresholds are assigned to the corresponding class, while those below the thresholds are assigned to the background.\u0000 \u0000 \u0000 \u0000 A new approach for borehole-derived porosity was developed in-house to overcome the limitations of existing techniques widely used in the industry. This approach capitalizes on BHIs for multiple analyses, including structural dip assessment, fault and fracture identification, and determi","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2024-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139890221","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Plug Your Way Through Downhole Restrictions","authors":"Jack Wang","doi":"10.2118/0224-0044-jpt","DOIUrl":"https://doi.org/10.2118/0224-0044-jpt","url":null,"abstract":"\u0000 \u0000 Unable to successfully deploy plug-and-perf bottomhole assemblies (BHA) to the desired depth has resulted in significant nonproductive time (NPT) in unconventional completions. These instances of NPT are primarily attributed to casing deformation, rather than plug presets.\u0000 To address these downhole restrictions, frac plugs with smaller outer diameters (OD) were introduced for stage isolation. This reduction in plug OD minimizes the risk of getting stuck in tight spaces, but it also compromises pressure ratings. This raises the risk of skidding (slip losses, anchoring) and leads to increased fluid usage for pumpdown.\u0000 These challenges not only risk well productivity, but also escalate completion time and costs. For a comprehensive solution, a smaller-OD frac plug is necessary to pass through tight spots, while maintaining anchoring, sealing, and reducing required pumped-fluid volume.\u0000 \u0000 \u0000 \u0000 The annular clearance between the plug OD and casing inner diameter (ID) significantly influences plug-and-perf operations. A smaller gap leads to advantages such as lower expansion rates for isolation, better anchoring, and reduced pumped-fluid volume, but it also heightens the risk of obstructions.\u0000 Conversely, a larger gap requires higher expansion rates for isolation, resulting in weaker anchoring, lower pressure rating, and increased fluid consumption, but reduces the likelihood of obstructions. In some frac operations, higher pressure is needed to break down the formation; thus, frac plugs with higher pressure ratings (smaller gap) are commonly favored. For instance, in 5.5-in., 20-lb/ft casing, typical frac plugs have an average OD of 4.4 in., an expansion rate of 8–12%, and a pressure rating of 10,000 psi.\u0000 In many 5.5-in., 20 lb/ft casedhole completions across the US and parts of China, the annular clearance between casing ID and frac plug OD is approximately 0.2 in. on the x-axis and 0.4 in. on the y-axis (Fig. 1). In this confined space, encountering debris, sand accumulation, or a deformed section during pumpdown can obstruct or fully trap the plug. To mitigate these uncertainties, smaller-OD plugs are used for such “emergency” scenarios.\u0000 Smaller-OD plugs have improved chances of navigating through tight spots, but they necessitate higher expansion rates for isolation, resulting in lower pressure ratings. For example, in 5.5-in., 20 lb/ft casing, reduced OD plugs have an average OD of 3.8 in., an expansion rate of 20–25%, and a pressure rating of 5,000 psi. They are more likely to fail due to their pressure limitations and use more fluid for pumpdown.\u0000 In cases where the use of normal-OD plugs is not feasible, opting for smaller-OD plugs, even though they might have a higher risk of failure, can be a valuable last resort. This approach is sometimes favored over entirely skipping the problematic stages without any form of stimulation.\u0000","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2024-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139684190","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"CO2 Injectivity Test Proves Concept of CCUS Field Development","authors":"C. Carpenter","doi":"10.2118/0224-0063-jpt","DOIUrl":"https://doi.org/10.2118/0224-0063-jpt","url":null,"abstract":"\u0000 \u0000 This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 216673, “CO2 Injectivity Test Proves the Concept of CCUS Field Development,” by Yermek Kaipov, SPE, and Bertrand Theuveny, SLB, and Ajay Maurya, Saudi Aramco, et al. The paper has not been peer reviewed.\u0000 \u0000 \u0000 \u0000 The complete paper presents a unique case study on injectivity tests done in Saudi Arabia to prove the concept of carbon capture, use, and storage (CCUS) capability. It describes the design of surface and downhole testing systems, lessons learned, and recommendations. The injectivity tests were effective in identifying and confirming the best reservoir for CO2 injection and defining the best completion strategy. Creating injection conditions close to CCUS is vital, especially in heterogeneous carbonate reservoirs where the petrophysical correlations for the reservoir model require calibration with dynamic data.\u0000 \u0000 \u0000 \u0000 The energy company has conducted an extensive evaluation campaign by drilling appraisal wells through multizone saline aquifer reservoirs on different sites close to potential sources of CO2 at the surface. The evaluation program included coring, openhole logging, formation testing for stress-test and water sampling, and injectivity testing in the cased hole. Apart from reservoir characterization, different completion strategies were evaluated by performing injectivity tests in both vertical and horizontal wells. The lower completion was represented by perforated casing and an open hole.\u0000 \u0000 \u0000 \u0000 Injection tests are a commonly used method in waterflood projects to evaluate the injectivity capacity of the well and reservoir. The test involves an injection period with one or more injection rates, followed by a falloff period (Fig. 1). During the injection period, the liquid is injected at a stable rate to reduce the risk of near-wellbore formation damage caused by fluid incompatibility or exceeding the fracture gradient and inducing formation fracturing.\u0000 The bottomhole-pressure data acquired during the test is analyzed using the pressure transient analysis method to estimate the permeability thickness, skin factor, and lateral heterogeneities. Additionally, the injection logging profile can be conducted along the sandface to assess completion efficiency and formation heterogeneity. By interpreting the results of the injection test, engineers can optimize the injection rate and improve the performance of the well and reservoir, ultimately leading to more-efficient oil recovery.\u0000 \u0000 \u0000 \u0000 The injectivity tests were conducted on virgin reservoirs using vertical appraisal wells that were sidetracked horizontally into the reservoirs with the greatest potential for storage. The reservoirs’ depths varied from 4,000 to 8,000 ft, with a normal gradient of reservoir pressure and temperature. The injectivity test design used reservoir properties estimated from the openhole evaluation, such as porosity, permeability, reservoir pressure, tempera","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2024-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139877235","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Study Investigates Seismic Monitoring for Carbon Storage Leak Detection","authors":"C. Carpenter","doi":"10.2118/0224-0086-jpt","DOIUrl":"https://doi.org/10.2118/0224-0086-jpt","url":null,"abstract":"\u0000 \u0000 This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 22980, “Carbon Storage Leak Detection Through Seismic FWI and RTM: Different Survey Analyses,” by Sajjad Amani, Kyoto University. The paper has not been peer reviewed. Copyright 2023 International Petroleum Technology Conference. Reproduced by permission.\u0000 \u0000 \u0000 \u0000 In the complete paper, marine seismic data processing is investigated as a tool for monitoring possible leakages in geological carbon storage. Because of the great importance of storage permanence, a precise leakage-monitoring strategy is crucial. The proficiency of seismic monitoring solutions for leakage monitoring can be affected by shallower layers as a result of structure, seismic wave attenuation, and leak size. The authors explore two popular seismic monitoring methods used in this application in different scenarios: full waveform inversion (FWI) and reverse-time migration (RTM).\u0000 \u0000 \u0000 \u0000 Among the various carbon capture and storage (CCS) options, underground storage in saline aquifers is the best-understood solution. To assure storage consistency and permanence, finding the best strategy to precisely detect possible carbon leaks is essential. A perfect method must demonstrate the difference between stored CO2 and injected CO2 to detect potential fast- and slow-leakage areas. The seismic monitoring technique is the most efficient approach in this respect.\u0000 Two popular tools for seismic monitoring are FWI and RTM. Several studies of their use in this application have been conducted. However, previous research did not analyze different survey arrays for carbon-leak detection using FWI and RTM. The current research aims to investigate quantitative aspects of CCS monitoring to conduct sensitivity analysis of the three different survey arrays [vertical seismic profile (VSP), crosswell, and surface] for different amounts of CO2-storage leakage in a saline aquifer reservoir. The capability of seismic-imaging methods for small amounts of leakage was tested. Comparison of these three arrays using monitoring methods such as RTM and FWI reveals their pros and cons in providing detailed information about the reservoir.\u0000 In this research, a simple synthetic model was built that closely fits actual reservoirs characterized by suitable physical features such as velocity and density. Subsequently, elastic wave propagation simulation was implemented by use of a finite-difference scheme over a physical model of the reservoir. Then, FWI was applied to enhance the accuracy of the model parameters. With an efficient forward-modeling and inversion scheme, RTM was used as a powerful imaging tool that provides final high-resolution results for monitoring CO2 migration and possible leakage. This process examined the synthetic model for different amounts of CO2 leakage in saline aquifers to evaluate the performance of CO2 leakage monitoring using the seismic method. The results of the different receiver and s","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2024-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139880865","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Multidisciplinary Approach Optimizes Characterization, Completion in Shale Play","authors":"C. Carpenter","doi":"10.2118/0224-0074-jpt","DOIUrl":"https://doi.org/10.2118/0224-0074-jpt","url":null,"abstract":"\u0000 \u0000 This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper URTeC 3871303, “Using a Multidisciplinary Approach to Reservoir and Completion Optimization Within the Woodford Shale Play of the Arkoma Basin,” by Stephen C. Zagurski, SPE, and Steve Asbill, SPE, Foundation Energy Management, and Christopher M. Smith, Advanced Hydrocarbon Stratigraphy, et al. The paper has not been peer reviewed.\u0000 \u0000 \u0000 \u0000 Subsurface complexities related to the formation of peripheral foreland basins can have significant effects on unconventional resource development. In the Arkoma Basin of southeast Oklahoma, the onset of thrusting and tectonic loading induced a complex series of dip/slip and strike/slip faults during basin formation. The operator used a series of technologies to increase understanding of the reservoir and its hazards and provide insight into economic implications for future development plans and strategies.\u0000 \u0000 \u0000 \u0000 The Woodford is primarily a Type II kerogen source rock. The formation typically is classified as either siliceous mudstone or cherty siltstone. Variable thermal maturity across the basin places the Woodford in both the wet-gas and dry-gas phase windows (moving west to east across the basin). Complex faulting regimes within the Arkoma add a layer of complexity to horizontal development of the Woodford.\u0000 The operator wanted to increase the understanding of the Woodford and the effects of faulting through the reservoir in a recent development unit in the liquids-rich fairway. The development unit consists of an existing parent well (Well X) and a pair of child wells (Well Y and Well Z).\u0000 The background of Unit XYZ begins with the completion of parent Well X 4–6 years before infill development. In this portion of the basin, Well X’s initial production rate and its cumulative production to date rank it in the top 25% of wells. The wellbore is subjected to a pair of faults and was drilled in the upper half of the Woodford. Placement of Well X is substantially further east than most parent wells because it is approximately 1,600 ft from the unit boundary. This limited infill development to two wells instead of three; the Arkoma typically has seen spacing of four, and sometimes five, wells per section. Wells Y and Z were planned and drilled east of Well X with 1,100–1,600 ft of well spacing. Well spacing in the unit was slightly hindered by surface location limitations and limited true vertical depth (TVD) between surface casing and landing point.\u0000 Structural complexity within the unit partially impaired infill development of the unit. Specifically, Well Y and its lateral length was shortened. In this portion of the Arkoma, fault-derived water production typically is the highest-weighted variable in a well’s operating expenditure. Thus, the ability to limit excess water production within Unit XYZ and the surrounding acreage is of paramount importance.\u0000","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2024-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139889618","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Autonomous Drilling Approach Uses Rotary Steerable System in Middle East Wells","authors":"C. Carpenter","doi":"10.2118/0224-0058-jpt","DOIUrl":"https://doi.org/10.2118/0224-0058-jpt","url":null,"abstract":"\u0000 \u0000 This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 22975, “Novel Approach to Autonomous Drilling Using Rotary Steerable System in Middle Eastern Oil and Gas Wells,” by Victor Oliveira, Saudi Aramco, and Mohammed Elsadig and Ayman Al-Ghazzawi, SPE, SLB, et al. The paper has not been peer reviewed. Copyright 2023 International Petroleum Technology Conference. Reproduced by permission.\u0000 \u0000 \u0000 \u0000 An operator focused on evaluating and validating a novel approach from its major directional-drilling-service provider using the autocurve-drilling mode to drill curved sections automatically without human intervention. The autonomous curve-drilling technology helped minimize human error, enhance accuracy of well positioning, and improve hole quality for drilling and workover operations.\u0000 \u0000 \u0000 \u0000 Rotary-steerable-system (RSS) intelligence has been improving since its introduction. Around 1990, when the RSS method was introduced, communication with RSS tools was only one-way; downlink commands were sent through flow variations, and the response was monitored. For corrections, human intervention was required by sending new downlink commands. Between 2003 and 2013, downhole automation design and analysis for RSS began with the introduction of closed-loop features in which either verticality or target inclination and azimuth in tangent sections can be maintained. The technology evolved to closed-loop responses in these vertical or tangent modes to adjust the trajectory automatically to the target directions within 0.5° in inclination and 2° in azimuth. The next step for automating the downhole trajectory control of RSS was to close-loop the curve section. This once took increased levels of focus from directional drillers to ensure that they continued reviewing directional responses of the RSS in different intervals to update steering requirements, the steering ratio, and toolface commands. This was a good driver for further improvement of RSS intelligence and updates to desired steering-requirement capabilities to automate curve-section directional control.\u0000 An autocurve autonomous downhole-automation-control system was developed to address the need to automate curved-section directional control. The intelligent algorithm was developed to change the communication process from including surface intervention to use of only a downhole closed-loop system once directional requirements were established. The system moved away from toolface and steering-ratio downlinking commands to dogleg and toolface commands. As a result, the RSS is no longer dependent on surface intervention for steering requirements but adapts to deliver required dogleg-severity (DLS) commands. This process solved the need for surface dependency. Upon acquiring this information, the tool uses the latest-known inclination and azimuth, and programmed rate of penetration, to create pseudochanges in direction and inclination to follow and automatically calc","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2024-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139891824","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Chevron Applies Some Unconventional Thinking To Try To Make Shale EOR a Standard Treatment","authors":"Stephen Rassenfoss","doi":"10.2118/0224-0024-jpt","DOIUrl":"https://doi.org/10.2118/0224-0024-jpt","url":null,"abstract":"In the shale business, the closest thing now to enhanced oil recovery (EOR) is improved techniques.\u0000 During an earnings call last November an analyst asked EOG Resources executives about their enhanced completion technique which EOG reported was adding 20% to first-year well production in the Permian.\u0000 Improved completions have allowed operators to significantly increase early production year after year, but after that, steep declines are a given.\u0000 Back in 2016, EOG was talking about how it was increasing oil production significantly by injecting millions of cubic feet of gas a day into wells in the Eagle Ford. It triggered an EOR field-testing boom by competitors hoping to match reported reserve increases of “30 to 70%.”\u0000 In a 2017 JPT story, Deepak Devegowda, a petroleum engineering professor at the University of Oklahoma, said, “This is the name of the game. Everybody is talking about EOR and pumping money into trials of EOR.”\u0000 Now the only mention of the acronym EOR on EOG’s website is an item in its corporate history timeline for 2016: “We commercialized the first enhanced oil recovery process, or EOR, in shale.”\u0000 In recent years, reported shale EOR work has been mostly in the form of occasional papers describing production uplift by companies selling ways to increase production by injecting gas or chemicals.\u0000 EOR effectiveness isn’t the issue, according to Todd Hoffman, a petroleum engineering professor at Montana Tech University who wrote two papers evaluating EOG’s methods cited in two Chevron papers.\u0000 “The EOG field work showed us that these projects can produce significant additional oil and be economically positive,” he said. The problem is that drilling and fracturing wells delivers “higher economic returns than the EOG-style EOR projects with the huge compressors, high gas rates, and high injection pressures.”\u0000 Last year in the middle of this EOR drought, Chevron did something different. It delivered two papers revealing a major company-scale effort to find ways to use chemical and gas injections to economically produce more oil.\u0000 The papers presented at the 2023 Unconventional Resources Technology Conference (URTeC) reported on field tests of surfactants and natural gas injection on Permian Basin wells which delivered sufficiently encouraging results to justify an expanded testing program. (URTeC 3870505 and URTeC 3871386).\u0000 Chevron described a systematic effort by its corporate technical unit and its Mid-Continent business unit to rethink shale EOR methods based on the unconventional nature of flow through fractured reservoirs and the economic realities in a business where new EOR technology is competing with the profitable status quo.\u0000 Its methods challenge accepted notions about the role of EOR. In SPE’s disciplines, EOR normally falls under the production topic, “marginal aging fields.” What Chevron tested is better described by the topic, “well interventions.”\u0000 Rather than looking at these techniques as a way to eke out the las","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2024-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139814200","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"President’s Column with Terry Palisch: The Value of Publishing Technical Papers for Your Career","authors":"Terry Palisch","doi":"10.2118/0224-0004-jpt","DOIUrl":"https://doi.org/10.2118/0224-0004-jpt","url":null,"abstract":"\u0000 \u0000 This transcript is an excerpt from the podcast episode.\u0000 \u0000 \u0000 \u0000 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.\u0000 \u0000 \u0000 \u0000 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.\u0000 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.\u0000 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.\u0000 \u0000 \u0000 \u0000 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?\u0000 \u0000 \u0000 \u0000 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.\u0000 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.\u0000 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.\u0000","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2024-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139830145","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Rig Automation Empowers Well Construction in Ecuador","authors":"C. Carpenter","doi":"10.2118/0224-0052-jpt","DOIUrl":"https://doi.org/10.2118/0224-0052-jpt","url":null,"abstract":"\u0000 \u0000 This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 216249, “Digital Innovation of Well-Construction Process in Ecuador Through Rig Automation,” by Karen Peña, Kevin Etcheverry, and Hugo Quevedo, SPE, SLB, et al. The paper has not been peer reviewed.\u0000 \u0000 \u0000 \u0000 Artificial intelligence (AI)-based digital drilling technology was implemented in two mature fields in Ecuador that represent 33% of the country’s oil production. The drilling campaign’s main strategy included the deployment of a novel automation solution on two rigs, resulting in the optimization of the well-construction process. In the complete paper, the authors present the results of implementation of a rig-automation solution applied to 20 wells in 2022.\u0000 \u0000 \u0000 \u0000 The authors detail the validation, optimization, and implementation of a drilling software to automate work flows and the installation and commissioning of associated hardware components. The following key indicators and objectives were established:\u0000 - Validation of drilling-software work flows\u0000 - Achievement of a 75% average in automation control\u0000 - Improvement of rate of penetration (ROP) by 5%\u0000 - Reduction of pre- and post-connection times by at least 30%\u0000 - Real-time tuning of parameters\u0000 - Training of all personnel involved in the use of the drilling-software package\u0000 - Installation and commission of hardware components\u0000 \u0000 \u0000 \u0000 The digital solution is an advanced software system that brings automation capabilities to drilling rigs, analogous to the different levels of automation found in automobiles. By drawing a parallel to car automation, one can better understand the system’s functionality and benefits.\u0000 Level 1 consists of task automation, comparable to automatic driving features such as cruise control. In this context, the drilling software takes on the role of automating specific tasks within the drilling process.\u0000 Level 2 involves process automation, similar to a car’s ability to autonomously park itself. The digital solution automates selected processes in drilling operations that enable efficient and precise execution.\u0000 Level 3 encompasses adaptive automation, akin to a self-driving car that dynamically adapts to its surroundings. The drilling software continuously analyzes the real-time conditions of the wellbore and suggests optimal drilling parameters based on proprietary algorithms that leverage the well-known DeTournay model principle.\u0000 The drilling software actively controls four key rig machines: the drawworks, topdrive, automated driller, and mud pumps. The solution adjusts drilling parameters intelligently, optimizing the drilling process and improving overall efficiency and drilling stability.\u0000","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2024-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139871414","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}