Day 2 Tue, October 04, 2022最新文献

{"title":"Buoyant Flow of H2 Versus CO2 in Storage Aquifers","authors":"Bo Ren, J. Jensen, I. Duncan, L. Lake","doi":"10.2118/210327-ms","DOIUrl":"https://doi.org/10.2118/210327-ms","url":null,"abstract":"\u0000 Hydrogen will play an important role in the quest to decarbonize the world’s economy by substituting fossil fuels. In addition to the development of hydrogen generation technologies, the energy industry will need to increase hydrogen storage capacity to facilitate the development of a robust hydrogen economy. The required hydrogen storage capacity will be much larger than current hydrogen and natural gas storage capacities. There are a several geological storage options for hydrogen that include depleted hydrocarbon fields and aquifers, where more research is needed until the feasibility to store hydrogen at scale is proven. Here, we investigate the buoyant flow of H2 (as a working gas) versus CO2 (as a cushion gas) separately in a representative storage aquifer. Buoyant flow can affect the maximum storage, capillary trapping, likelihood of leakage, and deliverability of aquifer-stored hydrogen.\u0000 After building a two-dimensional geological reservoir model initially filled with saline water, we ran numerical simulations to determine how hydrogen placed at the bottom of an aquifer might rise through the water column. The Leverett j-function is used to generate heterogeneous capillary entry pressure fields that correlate with porosity and permeability fields. Hydrogen viscosities were based on the Jossi et al. correlation, and the density was modeled using the Peng-Robinson equation of state. We then simulated several scenarios to assess flow during short- (annually) and long- (several years) term storage. For comparison purposes, we also ran CO2 storage simulations using the same geological model but with CO2-brine-rock properties collected from the literature.\u0000 For a representative storage aquifer (323 K, 15.7 MPa, and mean permeability of 200 mD), significant fingering occurred as the hydrogen rose through the saline water column. The hydrogen experienced more buoyant flow and created flow paths with increased fingering when compared with CO2. Individual hydrogen fingers are thinner than the CO2 fingers in the simulations and the tip of hydrogen finger fronts propagated upward roughly twice as fast as the CO2 front for a typical set of heterogeneity indicators (Dykstra-Parson’s coefficient Vdp = 0.80, and dimensionless autocorrelation length λdx = 2).\u0000 The implications of buoyant flow for hydrogen in saline aquifers include an increased threat of leakage, more residual trapping of hydrogen, and, therefore, the need to focus more on the heterogeneity and lateral correlation behavior of the repository. If hydrogen penetrates the caprock of an aquifer, it will leak faster than CO2 and generate more vertical flow pathways. We identify possible depositional environments for clastic aquifers that would offer suitable characteristics for storage.","PeriodicalId":113697,"journal":{"name":"Day 2 Tue, October 04, 2022","volume":"82 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133199692","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":"Using Nuclear Spectroscopy in Cased Hole Wells to Estimate Petrophysical Properties and Hydrocarbon Saturation in South American Freshwater Sands","authors":"L. Rodriguez, F. Angel, Elsa Casas, R. Pemper, N. Mekic, G. Schmid","doi":"10.2118/210111-ms","DOIUrl":"https://doi.org/10.2118/210111-ms","url":null,"abstract":"\u0000 Most of the mature South American oil and natural gas fields are represented by formations with moderate porosity, low resistivity, heavy oil, and general anisotropic behavior of other petrophysical properties. This leads to complex decision making when attempting to identify zones of interest with good reservoir qualities in addition to hydrocarbon saturation. These mature fields offer a unique challenge in that the petrophysical analysis needs to rely on data from newly drilled cased hole wellbores, necessitating numerous corrections. In this challenging environment, very few technologies can provide the data required for a precise petrophysical assessment. For this reason, a geochemical spectroscopy tool was employed with measurements that included elemental concentrations, the sigma formation cross section, and a direct measurement of the carbon concentration in the surrounding formation. The resulting data and innovative interpretation provided an accurate assessment of formation mineralogy including clay types, porosity, and hydrocarbon saturation.\u0000 These reservoirs, which have been in production for decades, contain relatively fresh water (approximately 2-5 kppm NaCl), moderate porosities (9 to 20 p.u.), and lithologies dominated by sand or sand/shale. The primary objective of the logging program was to incorporate nuclear spectroscopy applications to evaluate and characterize the zones of interest aligned with historical production data. In addition to the geochemical spectroscopy tool, the logging program also included gamma ray, spectral gamma ray, neutron porosity, and density. This suite of tools supplied the measurements required to characterize the formation through the determination of mineralogy, porosity, and hydrocarbon saturation.\u0000 The mineralogical model was based upon quartz, feldspar, pyrite, a highly conductive mineral, and numerous clays including illite, kaolinite, chlorite, and smectite. Open hole information from nearby wells was also incorporated into the petrophysical interpretation using normalization procedures and prediction analytics. Since this was a cased hole logging program, and calcium was a significant component of the cement, a cement-mimicking mineral was constructed based upon calcium oxide. This provided important quality control information regarding the condition of the borehole and cement placement, as very little calcite was present in the subsurface formations of the field.\u0000 Once the formation mineralogy, porosity, and matrix density were computed, the hydrocarbon saturation was calculated using two approaches: excess carbon and the ratio of carbon to oxygen elemental yields. The final interpretation provided key information, not only for the drilling campaign, but also for the workover planning and quantification of OOIP (original oil in place). Field examples are provided to demonstrate the complete workflow from the design of the logging program to the specialized interpretation methods and fin","PeriodicalId":113697,"journal":{"name":"Day 2 Tue, October 04, 2022","volume":"93 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133321057","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":"Improved Well Spacing Decision Using RTA: Workflow to Translate RTA Half-Length to Actual Depletion","authors":"V. Muralidharan, S. Esmaili","doi":"10.2118/210073-ms","DOIUrl":"https://doi.org/10.2118/210073-ms","url":null,"abstract":"\u0000 Rate Transient Analysis (RTA) is widely used in the industry to understand the Stimulated Reservoir Volume (SRV) of horizontal wells for forecasting and for comparing well performance. However, significant well interferences are observed while using SRV dimensions obtained from analytical models in making well spacing decisions. The reason for that is the assumption of rectangular shape for SRV representation, which is not a realistic case. Upon drilling several pressure monitoring wells in the Permian Basin and comparing them with multiple diagnostic tools, we found that the actual SRV vertical drainage is not uniform. Inaccurate characterizations of fracture height and half lengths would result in either overcapitalizing the project or not draining the reservoir efficiently.\u0000 The objective of this study is to provide guidance for improving stacked development in the Permian Basin with the understanding of depletion patterns around individual wells both vertically and laterally. Pressure depletion profiles from several vertical monitoring wells in the Permian Basin are used to define the depletion patterns. Downhole microseismic data are also utilized to bridge any gaps. Several fully developed sections are used as case studies to validate the frac geometries and assumptions. The learnings from this study will be tremendously useful in applying RTA to optimize vertical and lateral spacing of unconventional wells across the Permian Basin.","PeriodicalId":113697,"journal":{"name":"Day 2 Tue, October 04, 2022","volume":"9 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"126115601","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":"Machine and Process Automation are Improving Personnel Safety and Drilling Performance","authors":"Michael Whatley, Arima Ayanambakkam, Derek Patterson, Blakley Farrow, Le Feng, Parker Hewitt","doi":"10.2118/210368-ms","DOIUrl":"https://doi.org/10.2118/210368-ms","url":null,"abstract":"\u0000 The industries’ number one priority is ensuring everyone goes back home in the same condition they came to work. With that guiding principal in mind, how could a drilling contractor work to substantially reduce our crews health, safety, and environment (HSE) exposure? Engineer solutions that take them off the most dangerous place on a drilling rig. Traditional drilling processes require personnel to manually handle tubulars while making connections, building stands, or racking back pipe. This requires personnel to perform strenuous tasks in dangerous areas. These areas often require personnel to work near moving machinery. Manual operations often lead to high degrees of variability in performance based on rig crew experience and familiarity of the operations.\u0000 Development of a fully automated rig required overcoming many challenges to process tubulars from the ground to well center. New machines were designed to meet the automation requirements. The ground handling system was designed to clean, dope, and measure pipe. The robotic pipe handler was designed to handle retrieving tubulars from the ground handling system, deliver to well center and spin in the connection. The automated floor wrench is responsible for making up connections. The rack and pinion hoisting system was designed to handle the drill string with precision and eliminate the need to slip and cut drill line.\u0000 To achieve the desired automated tripping and drilling process automation, a rig operating system with sequencing functionality, tubular management, and zone management was required. The rig operating system integrates the different machines and manages the necessary protections at the machine layer. The sequencing layer is responsible for coordinating the process automation at the appropriate set points for rotary drilling, slide drilling, tripping, and casing connections.\u0000 The robotic rig has currently completed 9 wells and has continuously improved since the start of drilling in August. The drilling connection times have improved by 28% and the rig became the third fastest across the fleet. Additionally, the rig has improved its casing running performance by approximately 43% and is now within a few joints of other top performing rigs in the fleet. Fully automated control of these processes guarantees consistent and repeatable performance across the wells drilled. This is all being done without the need to have personnel handling tubulars in the mast or on the rig floor.\u0000 The success of this first of its kind robotic rig can be attributed to partnerships with the operator, the drilling operations team, the rig engineering team and the controls and automation team. The teams collaborate to identify areas for improvement to continuously drive better, safer, and faster drilling.","PeriodicalId":113697,"journal":{"name":"Day 2 Tue, October 04, 2022","volume":"7 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125558637","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":"Perf Guns, They’re Not Just for Holes Anymore! Perf Cluster Tracer Injection","authors":"Christopher Squires, Brad Leonard, Shaun Geerts, Matthew Clay","doi":"10.2118/210134-ms","DOIUrl":"https://doi.org/10.2118/210134-ms","url":null,"abstract":"\u0000 Oilfield water and oil tracers have historically been pumped into the fracturing fluid during well stimulation. This paper will introduce an alternative method of injecting oilfield tracers that utilizes perforating guns with energetic propellant to force the tracer into a perforation cluster prior to fracturing operations. Direct tracer injection from perforating guns offers several advantages to operators that are interested in oilfield tracer diagnostics, they include:Monitoring a wells oil or water returns down to an individual cluster level of resolution.Energetic propellent assisted perforation cluster breakdown.Direct tracer injection into clusters for wells that are: Perforated but not hydraulically fractured.Bullhead refracturing treatments with long open intervals of newly fired perforations.Not sufficiently isolated between stages from poor cementing or leaking plugs.Not isolated or experimentally isolated between stages.\u0000 Oilfield tracers in solid form were first injected into perforation clusters with energetic propellants on two Marcellus Shale wells. The primary purpose of this experiment was to determine if Perforation Gun Tracing (PGT) could be used to provide flow-assurance diagnostic information to the well operator. Additionally, standard liquid water tracers were also injected into the flowstream during the corresponding fracture treatment stages and used as a control for the PGT. Both tracer injection methods indicated that the toe side of the wellbore was contributing to the fluid returns profile and also showed similar trends in tracer response over time. This experiment showed that PGT could provide valuable diagnostic information to well operators.\u0000 Several additional field trials that exploit the unique benefits of PGT were completed after the success of the initial experiment and are included in the case studies section of the paper. In each case, PGT was able to provide the intended diagnostic which included flow-assurance, flow-profiling, fracture driven interactions and/or refracturing effectiveness.\u0000 In refracturing, PGT has tremendous benefits because the energetic propellent can help the new perforations breakdown and compete with the existing broken down and eroded perforations. Additionally, unique tracers are injected at several known cluster depths throughout the lateral. Any returns of the unique tracers in the flowback water will correspond to fracturing fluid that has contacted the depth of that specific traced cluster. This provides an operator valuable diagnostic information to determine how deep their refracture treatment was able to reach into the lateral. PGT also delivers information on the returns of an individual cluster, without post-frac well intervention or permanent hardware installation.","PeriodicalId":113697,"journal":{"name":"Day 2 Tue, October 04, 2022","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"129928433","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":"Typical Curve and Diagnosis Method for Identifying Fracture Closure Points of Fractured Wells in Flowback and Early-Time Production Period for Tight Oil Reservoir – A Field Example from Ordos Basin in China","authors":"Zhao‐Min Sun, Linsong Cheng, Xulin Du, P. Jia, R. Cao, Yongchao Xue","doi":"10.2118/210272-ms","DOIUrl":"https://doi.org/10.2118/210272-ms","url":null,"abstract":"\u0000 Fracturing fluids will carry an amount of proppant flowing back to the wellbore due to the inappropriate flowback schedule, which causes some parts of fractures to be closed without support. The appearance of closed fracture sections without support (pinch point) has a serious negative effect on well performance and is also a potential signal of refracturing. A four-region model considering fracture closure is developed to detect pinch points by analyzing production data in material equilibrium time.\u0000 Therefore, a novel four-region flow model is proposed to study the influence of pinch points on well dynamics performance in the initial stage of production and to diagnose the pinch point. In this model, the fluid flow to the wellbore is regarded as three parts: matrix, fracture, and pinch points. The position of the pinch point on the fracture (near wellbore) is considered. The existence of pinch points makes the fracture conductivity segmented, and the partial closure of fracture can be simulated by setting different fracture lengths, widths, and permeability. The flow in each region is treated as the linear flow and is coupled through boundary conditions and flux supply. Thereby, the mathematical model of flow containing pinch points is established.\u0000 This paper analyzes the production data of oil well, draws the logarithmic curve of RNP and its derivative RNP’ versus the material balance time (MBT), and conducts rate transient analysis to determine the occurrence of pinch points. In the case of the near-wellbore pinch point, the slope of the first half of RNP curves is relatively small, while the slope of the back section is about 1/2. Compared with RNP curves, the early slope of RNP’ curves is relatively large and gradually changes into the linear flow stage with a slope of 1/2. Different properties of pinch points mainly affect the slope of the left and right ends of RNP and RNP’ curves. The new analysis method can be used to analyze the influence of fracture closure position and degree of fracture closure on well productivity. Finally, the novel four-region flow analysis model was applied to the analysis of oil production data from a typical well in Ordos Basin. The length, width, and permeability of the near-wellbore fracture closure section can be obtained by fitting the proposed chart.\u0000 The novel four-region flow model method and its curve characteristics provided in this article can be used as an important reference for judging whether there is a pinch point in fracture. It has a certain guiding significance for the formulation of fracturing schemes for new wells and whether old wells need refracturing in actual production.","PeriodicalId":113697,"journal":{"name":"Day 2 Tue, October 04, 2022","volume":"58 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"130287501","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":"Applying Survival Analysis to Sand Failure Control Risk","authors":"Huihui Yang, A. Tallin, Ligang Lu, Xiaohui Xiao, Lisa Valteau, Jia Wei, Jay Chen","doi":"10.2118/210255-ms","DOIUrl":"https://doi.org/10.2118/210255-ms","url":null,"abstract":"\u0000 Sand production affects safety, reliability, equipment integrity and economics. To help production engineers understand and quantify sand control risks, we built sand control survival application. This application displays how survival is impacted by operating and well parameters as a function of cumulative production, which can help to save oil and gas industry hundreds of millions of dollars per year. Our application uses a dataset that tracks survival status and corresponding cumulative productions for more than 300 completions in GOM. Field data covering water cut, flowing pressure decline, and sand control survival was compiled and analyzed to determine the impact these both single and multiple cofactors on survival, which save time and cost while improving the overall quality of information.","PeriodicalId":113697,"journal":{"name":"Day 2 Tue, October 04, 2022","volume":"42 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"130302494","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":"Application of Key Deepwater Lessons Learned in Marginal Deepwater Development, Offshore Malaysia","authors":"Aizuddin Khalid, N. Hamza, Mas Rizal A Rahim, Amir Ridzwan A Rahman, Thanavathy Patma Nesan, Norhayati M Sahid","doi":"10.2118/210393-ms","DOIUrl":"https://doi.org/10.2118/210393-ms","url":null,"abstract":"\u0000 L & B fields offshore Sabah, Malaysia will be the next deepwater development in Malaysia after Kikeh, Siakap North-Petai, Gumusut-Kakap & Malikai. However, in comparison, L & B are considered marginal in terms of recoverable volumes and size of project, making it crucial to design and execute the project sharply to ensure value delivery. 5 key deepwater lessons learned areas are discussed in this paper as applied to L & B Field Development Plan (FDP) to ensure technical robustness based on experience of surrounding deepwater fields.\u0000 The first key area is subsea production stability and flow assurance. Among critical evaluations conducted were techno-commercial comparison of dual-loop pipe-in-pipe against heated pipe-in-pipe, upfront artificial lift plans, and water injectors design to avoid hydrates formation as observed in another field. The second critical area is in drilling where key lessons were to conduct thorough geohazard analysis for hazard identification and avoid wellhead subsidence. Thorough geomechanics and fracture gradient were also assessed to identify requirements for managed-pressure drilling and for backup designs. The third key area is well integrity, productivity and injectivity where sand production and fines migration risks need to be addressed through well completion strategy. The reservoir management plan must also reflect realistic production and injection plans and data crucial for monitoring. The fourth key issue is with regards to subsurface complexity in deepwater turbidite environment with risks to production attainability vis-à-vis reservoir connectivity and compartmentalization issues. A no-stones-unturned approach was taken integrating available static and dynamic data to estimate a robust recoverable volume. The fifth critical area is well startup and unloading procedures, which is important for well productivity. Model iterations were needed to conduct methodical well bean-up to eliminate risk of fines movement.\u0000 Application of lessons learned in these 5 key areas led to robust development plans with mitigations for risks common to deepwater developments offshore north Borneo. For flow assurance strategy, the evaluation led to dual-loop design, proactive artificial lift strategy and optimum water injector locations. Drilling requirements are identified for MPD and backup slim-hole designs. To ensure productivity and injectivity, long highly deviated wells, with downhole sand mitigations, are designed for maximum contact and reduced required drawdown. Skin factors were applied in subsurface modeling as observed in other fields to risk the production targets. The model was also calibrated with dynamic data gained from well tests and pressure points to provide realistic production estimates, with a well sequence plan to observe actual performance and optimize next well locations if necessary. For well startup procedures, model iterations guided by analogue fields’ experiences led to optimum startup designs for ","PeriodicalId":113697,"journal":{"name":"Day 2 Tue, October 04, 2022","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"129096061","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":"Effective Conformance Control Strategies in Mature Waterfloods with Comingled Injection","authors":"B. Yadali Jamaloei","doi":"10.2118/210117-ms","DOIUrl":"https://doi.org/10.2118/210117-ms","url":null,"abstract":"\u0000 The Sparky/General-Petroleum/Rex/Lloydminster formations are subject to a mature waterflood (1300+ vertical/horizontal wells) in Chauvin, Alberta, where permeabilities and viscosities range from 10 to 200 mD and 40 to 150 cp, respectively, and adverse mobility ratio, injection-induced fracturing, and thief zones trigger water channeling. Conformance polymer-gel squeeze is common for alleviating channeling. With sufficient gel (10-25% of channel volume) selectively placed into water-bearing channels, injected water is effectively redistributed to improve sweep efficiency and pressure support.\u0000 Selective gel squeeze with diverter entails injecting a diverter slug ahead of self-crosslinking gels to divert gels to high-permeability water-bearing channels, avoiding diversion into lower-permeability and/or oil-bearing pores. Selective gel squeezes are complex, costly, and erode profit margins in mature waterfloods. In simpler-to-execute, more-economical non-selective gel squeezes (without diverters), bullhead gel treatments are ‘designed’ to enter higher-permeability zones. In this work, effective, economical conformance control strategies were developed using non-selective gel squeezes. Hall/Chan/Conformance/Heterogeneity-Index Plots were used to identify candidates (26 injectors supporting 300+ producers) and channel volumes. Gel strength of crosslinked acrylamide-polymer (4000-15000 PPM concentrations) was monitored using Sydansk grading. During the treatment, offsets were monitored for polymer breakthrough using flocculation tests. Any offending producer was shut in until resuming water injection. After treatment, water post-flush displaced the gel, and injector was shut in for 1-4 weeks (longer shut-in for lower polymer concentration) to allow gel to set before resuming water injection.\u0000 Non-selective bullhead gel with low-to-medium strength, lower treatment rate, and extended water post-flush triggers both near-wellbore diversion and protection against crossflow back into offending thief zones deeper in the reservoir, resulting in 40% costs reduction and up to 50% oil rates improvement with lower treatment volumes (5-10% of channel volume). Sufficient low-to-medium strength gel is required for deeper gel placement in the reservoir. Injecting gel in stages of increasing polymer concentration ensures that lower polymer-concentration gels at the leading edge of the treatment occupy rock furthest from the wellbore where they will not require as much strength to resist lower differential pressure to which they will be exposed. Conversely, higher polymer-concentration gels injected at the end of the treatment occupy rock nearest the wellbore where more strength is required to resist higher differential pressure. Furthermore, injecting gel at lower rates ensures that it remains selective to higher-permeability, more-conductive pores (i.e., water flow paths), minimizing gel diversion into oil-bearing pores. Shut-off candidates exhibit out-of-zone injec","PeriodicalId":113697,"journal":{"name":"Day 2 Tue, October 04, 2022","volume":"7 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"129484840","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":"Compressed Air Pneumatics for Methane Mitigation","authors":"I. Garaway, Kevin Pang","doi":"10.2118/209996-ms","DOIUrl":"https://doi.org/10.2118/209996-ms","url":null,"abstract":"\u0000 \u0000 \u0000 With the challenge of reaching carbon neutrality, the energy industry will need to be transformed. One of the key challenges facing the industry is eliminating Scope 1 emissions from the pneumatic devices used in wellpad automation and control. This practice accounts for roughly 45 million tons of CO2E/yr in the United States alone. Eliminating these emissions from existing brown-field sites is a significant challenge given that many of these well pads are in remote locations and suffer from a lack of reliable and sustainable electric power.\u0000 \u0000 \u0000 \u0000 Compressed Air Pneumatics (CAP) is an innovative technology that replaces the methane emissions of pneumatic devices with clean, dry, compressed air. By employing highly reliable free-piston Stirling engine technology the end-user utilizes a small fraction of the normally vented methane to efficiently generate continuous and reliable electric power and clean, dry, compressed instrument air. CAP systems conserve valuable instrument gas and entirely eliminate methane venting at the well pad. They also eliminate the \"wet-gas\" issues associated with low-bleed pneumatic device contamination. In addition to compressed air for well pad automation, CAP technology is able to further provide additional utility grade electric power for additional well pad loads. Operators are able to further reduce their carbon footprint by harnessing the reject heat of the Stirling engine to keep process lines warm, further displacing the emissions of low-efficiency gas fired heaters. Another advantage that Stirling engine based CAP solutions gives upstream producers is the option to commission their instrument air system on tanked fuels like propane and readily switch over to instrument gas once wells are operational.\u0000 \u0000 \u0000 \u0000 A deployed CAP system on a multi-well pad in the Barnett Shale formation in Texas mitigated the vented emissions of 42,000 SCF of Methane in a 30-day period, which is equivalent to the removal of over 1,000 tCO2E on an annual basis, equivalent to removing 200 cars of the road. This same wellpad had zero downtime due to lack of pneumatic control or vent contamination across the same period. In addition to pneumatic control the CAP technology provided the wellpad prime power electricity, eliminating the need for large solar panels and cycling battery banks.\u0000 \u0000 \u0000 \u0000 This technology when rightsized can maximize system value, driving down the cost of methane abatement below $2/tCO2e\u0000","PeriodicalId":113697,"journal":{"name":"Day 2 Tue, October 04, 2022","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"128939065","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}