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Collaborating Authors
injection
Serge A. Shapiro is a European geophysicist known for many areas of rock physics and seismic research including advances in microseismic monitoring and applications of passive seismic measurements for reservoir characterization. He received his Diploma in Applied Geophysics from Lomonosov Moscow State University (1982). From 1982 to 1991 he worked as a geophysicist at the Moscow Research Institute VNIIGeosystem, where in 1987 he received his PhD degree. The main subject of his research was seismic attenuation and scattering. From 1991–1997 he worked at the Geophysical Institute of Karlsruhe University in Germany.
- Europe > Germany (0.56)
- Europe > Russia > Central Federal District > Moscow Oblast > Moscow (0.47)
- Information Technology > Knowledge Management (0.40)
- Information Technology > Communications > Collaboration (0.40)
Mirko van der Baan is a professor at the University of Alberta in the Department of Physics, specializing in exploration seismology. He graduated in 1996 from the University of Utrecht in the Netherlands, obtained a PhD with honors in 1999 from the Joseph Fourier University in Grenoble, France, and then joined the University of Leeds, UK, where he became the reader of exploration seismology. He also holds an HDR (Habilitation) from University Denis Diderot, Paris, France. Mirko is currently the director of the Microseismic Industry Consortium, a collaborative venture with the University of Calgary, dedicated to research in microseismicity. He also is one of the founding members of the Integrated Petroleum Geosciences (IPG) professional MSc program at the University of Alberta.
- North America > Canada > Alberta > Census Division No. 6 > Calgary Metropolitan Region > Calgary (0.27)
- Europe > France > Île-de-France > Paris > Paris (0.27)
- Europe > France > Auvergne-Rhône-Alpes > Isère > Grenoble (0.27)
- North America > United States (0.89)
- North America > Canada (0.89)
- Europe > Russia > Northwestern Federal District > Komi Republic > Timan-Pechora Basin > Pechora-Kolva Basin > Usa Field (0.89)
- Information Technology > Knowledge Management (0.40)
- Information Technology > Communications > Collaboration (0.40)
Induced seismicity refers to typically minor earthquakes and tremors that are caused by human activity that alters the stresses and strains on the Earth's crust. Most induced seismicity is of a low magnitude. A few sites regularly have larger quakes, such as The Geysers geothermal plant in California which averaged two M4 events and 15 M3 events every year from 2004 to 2009.[1] Results of ongoing multi-year research on induced earthquakes by the United States Geological Survey (USGS) published in 2015 suggested that most of the significant earthquakes in Oklahoma, such as the 1952 magnitude 5.7 El Reno earthquake may have been induced by deep injection of waste water by the oil industry. "Earthquake rates have recently increased markedly in multiple areas of the Central and Eastern United States (CEUS), especially since 2010, and scientific studies have linked the majority of this increased activity to wastewater injection in deep disposal wells."[2][3][4][5][6][7][8]
- North America > United States > California (0.50)
- North America > United States > Oklahoma (0.31)
- Water & Waste Management > Water Management (1.00)
- Energy > Renewable > Geothermal > Geothermal Resource (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Oceania > Australia > South Australia > Cooper Basin (0.99)
- Oceania > Australia > Queensland > Cooper Basin (0.99)
- North America > United States > California > Mayacamas Mountains > Geysers Field (0.99)
- Oceania > Australia > Victoria > Bass Strait > Gippsland Basin (0.89)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Non-Traditional Resources > Geothermal resources (1.00)
- Health, Safety, Environment & Sustainability > Environment > Water use, produced water discharge and disposal (1.00)
- Health, Safety, Environment & Sustainability > Environment > Waste management (1.00)
- Information Technology > Knowledge Management (0.40)
- Information Technology > Communications > Collaboration (0.40)
- Information Technology > Knowledge Management (0.40)
- Information Technology > Communications > Collaboration (0.40)
There is a strong resemblence between the techniques used in clinical medicine and geophysical prospecting. Here, I will refer to this resemblence within the context of the 4-D seismic method. A heart patient is monitored from year to year by the patient's cardiologist to observe and detect changes in the parameters that describe the heart itself and its condition to sustain the patient's life, and the composition of the patient's blood. By using an echocardiogram derived from ultrasound waves, the cardiologist measures the size of the heart and observes whether the valves have any leakage. By recording an electrocardiogram, the cardiologist observes the systolic pressure associated with the rythmical contraction of the heart during which the blood is pumped out and the diastolic pressure associated with the rythmical dilatation of the heart during which the blood is pumped in.
- Geophysics > Time-Lapse Surveying > Time-Lapse Seismic Surveying (1.00)
- Geophysics > Seismic Surveying (1.00)
- Health & Medicine > Therapeutic Area > Cardiology/Vascular Diseases (1.00)
- Health & Medicine > Diagnostic Medicine (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Information Technology > Knowledge Management (0.40)
- Information Technology > Communications > Collaboration (0.40)
Application of Foamers in Unconventional Oil Well with Low Water Cut
Villanova, Joanna (PECOM Energía S.A.) | Luliano, Florencia (Pan American Energy) | López, Jimmy (PECOM Energía S.A.) | Emiliani, Verónica (Pan American Energy) | Bragagnolo, Marcos (Pan American Energy) | Blanco, Adriana (Pan American Energy)
Abstract Coiron Amargo Sureste is a Pan American Energy area located in the Neuquen basin which currently has 13 unconventional oil wells under production. One of these producing wells presents an unstable production pattern which is associated with the presence of slugging. In fact, the present work focusses on the application of strategies to improve its extraction system. A pilot test for injecting a foaming agent suitable for high cut crude oil through a capillary system was carried out at an estimated depth of 2750 m. The chemical treatment implementation, as well as its control, monitoring, and evaluation, were combined in an operational strategy specifically designed for this purpose. Firstly, the initial step was a laboratory test following an adaptation of the standard ATSM-D892 in which a Nonionic/Amphoteric surfactant was selected. Subsequently, the designed product was tested in a 15-day field trial in which daily data involving oil production and foam breakdown was continually collected. The selected product was injected through a batch mode having the well closed for 12 hours to recover pressure. Afterward, a continuous dosage of 250 ppm concentration was injected through the downhole capillary system. Obtained results showed an average oil production increase of 1.7 m/d (10.7 bpd) during the surfactant injection. Due to these significant results, the surfactant was continuously injected for several months until the artificial lift method was changed. Introduction During the regular life cycle of oil and gas wells, there is a common reduction in the bottom hole pressure (BHP) over time that leads to produce liquid loading problems. It means that the well doesn’t have proper liquid production since gas velocity is not strong enough to mobilize that liquid phase, leading to its accumulation on production tubing. The application of foaming chemicals is a common strategy in gas wells with liquid loading problems since these products, by reducing the critical velocity of the gas phase, facilitate the transport of liquids to the surface. Simultaneously, this reduction in critical velocity helps to lower relative density of accumulated fluids and, therefore, reduced back pressure. This foaming chemicals are commonly applied through different ways: downhole capillaries for continuous injection; liquid batch; or solid bars directed into the production tubing.
Effect of Multi-Scale Natural Fractures on Hydraulic Fracture Propagation in Shale Reservoirs: A Numerical Study
Xiong, Zhuang (China University of Petroleum, Beijing) | Hu, Xiaodong (China University of Petroleum, Beijing) | Ma, Shou (SinoFTS Petroleum Services Ltd, Beijing, China ) | Huang, Haoyong (PetroChina Southwest Oil & Gasfield Company, Chengdu, China ) | Song, Yi (PetroChina Southwest Oil & Gasfield Company, Chengdu, China ) | Zhou, Fujian (China University of Petroleum, Beijing) | Dong, Enjia (China University of Petroleum, Beijing) | Zhou, Qianlong (China University of Petroleum, Beijing)
Abstract Hydraulic fracturing technology has been widely used to stimulate the production of shale oil and gas reservoirs. However, the extensive presence of a large number of natural fractures in shale reservoirs makes them highly inhomogeneous, which directly affects and restricts the hydraulic fracturing effect in the reservoirs. How to effectively activate natural fractures of different scales in shale gas reservoirs to form a complex fracture network is a key technical issue related to shale gas exploration and development. In this paper, numerical simulation is carried out to investigate the effect of multi-scale natural fractures on hydraulic fracture propagation in shale reservoirs. First, a two-dimensional fluid–solid fully coupling finite element model in shale reservoirs containing natural fractures of different scales is established based on the global cohesive method to simulate the random propagation of hydraulic fractures. Secondly, the accuracy of the model was verified through the published numerical results. Finally, the effects of multi-scale natural fracture distribution, different-scale natural fracture distribution, and different natural fracture angle distribution on hydraulic fracture propagation morphology are discussed in detail through numerical simulation runs. Our model and study can provide some useful insights for evaluating the scale of hydraulic fracturing in shale reservoirs, and provide a reference for the decision of fracturing construction in the field. Introduction Hydraulic fracturing has been greatly developed in the past decades and has become one of the most widely used shale reservoir stimulation methods in low permeability reservoirs (B. Chen et al., 2022; Lecampion et al., 2018). Microseismic monitoring(Warpinski, 2004) and optical fiber sensor monitoring (Hu et al., 2023; Liu et al., 2021) results show that shale reservoirs have obvious heterogeneous characteristics and developed natural fractures. The formation of complex hydraulic fracture networks in shale reservoirs is strongly influenced by the distribution of pre-existing natural fractures and the interaction characteristics of multiple fractures. How to effectively activate natural fractures of different scales in shale gas reservoirs and obtain an ideal complex fracture network directly restricts the effectiveness of hydraulic fracturing.
- Asia > China (0.47)
- South America (0.28)
- Research Report > Experimental Study (0.34)
- Research Report > New Finding (0.34)
Abstract Exploitation of the Vaca Muerta formation in Argentina poses several challenges. During the production stage of the wells, paraffin precipitation in the tubing and flow assurance in the wells is vital. Initially, when natural flow begins, production temperatures are above the temperature corresponding to that of wax appearance; therefore, there is no formation of crystals inside the production tubing. As time goes by, wax precipitation begins to be noticed.The present work attempts to summarize the experiences acquired from production engineering concerning wax in wells that flow naturally, as well as in a more mature stage, of wells with Gas Lift assistance. Methods/Procedures/Process: In 2021, severe cases of deposition were observed within the gas-assisted well installation. This involved cleanup actions that took several days to complete and affected a variety of resources. As the cases began to multiply, it was decided to implement a comprehensive prevention/mitigation plan through the study of each of the components of the paraffin control triangle. This plan was framed within a project that covers chemical selection, well maintenance with wireline equipment, use of hot water, optimization of wireline equipment operation, and resource scheduling. Results/Observations/Conclusions: The generation of a statistical base from field data allowed us to detect the critical flow rate where, if this is not followed by the start of inhibitor injection or with a change in the dosage, it can obstruct the flow passage in the downhole installation. Additionally, with the information collected, it has been possible to determine the expected depths of deposition, as well as the detection of possible follow-up variables.
- South America > Argentina > Patagonia > Neuquén > Neuquen Basin > Vaca Muerta Shale Formation (0.99)
- South America > Argentina > Patagonia > Neuquén > Neuquen Basin > Vaca Muerta Field > Vaca Muerta Shale Formation (0.99)
Abstract One of the biggest challenges for Carbon Capture and Storage/Carbon Capture, Utilization and Sequestration (CCS and CCUS) implementation is to comply with the established regulation as there is not a worldwide accepted framework. One of the most important prerequisites is the assessment of the risks involved in the field implementation of such technologies. The only way to reduce risks is through a rigorous storage site (rock and fluids) characterization. In some cases, correlations can be used but the risk associated is remarkably high, so the evaluation of the rock-fluid system is mandatory. For unconventional reservoirs, this phase is hard due to the difficulties associated with the laboratory requirements in terms of equipment and methods. It is necessary to consider that (CCS/CCUS) projects are quite different, two projects are not the same, each project depends on the properties and conditions, so like in the reservoir exploitation, every storage site must be well characterized. The high heterogeneity of the rock-fluid storage site makes each project overly complex. So, a rigorous characterization is needed for each project. From the literature it is possible to establish a laboratory workflow for carbon storage and utilization; however, specific methods should be used according to the rock type from the fluid sampling to get representative samples to the advanced testing including fluid-fluid and rock-fluid compatibility to characterize potential reactions that could happen and to evaluate how the porous volume change in presence of CO2, seals characterization for geomechanically modeling, trapping mechanisms, mobility should be evaluated at current conditions, capillary pressure and the threshold pressure are needed to minimize the release of CO2 during the storage. Core flood tests are the only way to get the parameters needed for modeling and to understand the injectivity and reactions between the CO2 and the rock and fluids in the storage site. In this paper we present a series of laboratory practices for both single phase core flood and 2-phase displacement experiments aimed to improve existing protocols and get more reliable data and hence a more precise reservoir model. The proposed protocol includes the need to perform experiments using the right conditions to diminish risks, proper handle of samples, selection of the test and method to get the right parameters according to reservoir type, and recommendations for testing. Results for steady state relative permeability tests from conventional workflow versus proposed workflow are presented together with a summary of lessons learned and best practices to optimize laboratory evaluation resulting in cost and time reduction.
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.47)
Compositional and Numerical Modeling of the HnP Technique by Using Both Dry and Rich Gas to Increase Production and Reserves in Shale Oil Wells in Vaca Muerta
Sancet, G. Fondevila (Capex SA) | Ponce, J. (Capex SA) | Gilardone, C. (FDC de Argentina SRL) | Canel, C. (FDC de Argentina SRL) | Albuquerque, L. (FDC de Argentina SRL) | Cardozo, J. (FDC de Argentina SRL)
Abstract To optimize oil recovery from Vaca Muerta (°API 40, GOR 617 scf/stb), lab tests were conducted to assess miscible gas injection. This unconventional formation with average initial pressures of 8500 psia and fluid bubble pressures between 1800 and 3200 psia, shows a significative oil decline. The formation's low transmissibility suggests that Huff and Puff gas injection is the best recovery option. This method not only reduces the decline rate but also improves wellbore flow. This work considers from PVT tests of the fluid to production forecasts by numerical simulation. The findings will be key to a pilot design. PVT tests were conducted to represent fluid behavior under reservoir conditions. Swelling tests were also performed to analyze the mixtures between the original fluid and injected gas, and two types of gas were studied: dry gas (from the Turboexpander plant outlet) and rich gas (primary separator). During the swelling tests, a known gas was injected into the original fluid at bubble pressure and reservoir temperature, increasing the pressure until total miscibility was achieved. This process was repeated with new gas fractions, determining properties and saturation pressures for each mixture. The study and the pilot test were conducted in the Agua del Cajón Area, in central-eastern Neuquén. The previously detailed laboratory tests served as a basis for characterizing the fluids and adjusting the state equation models that simulate their thermodynamic behavior. Once defined, several runs were carried out in the numerical simulator to optimize oil recovery efficacy through gas injection in the reservoir, considering various gas injection compositions (dry or rich gas), for the pilot well implementation design. The behavior of the wells with the new fluids to be produced was also evaluated, as well as the separation conditions for each injection alternative, seeking to optimize operating conditions to maximize oil recovery. Extremely interesting results were obtained showing an increase in RF and observing the change in the original fluid's behavior from light black oil to a "near critical" fluid after gas injection. This promotes the application of this technique to increase associated production and optimize the development of this type of reserves. A pilot will be designed to be implemented in a current well in the area to evaluate performance and model adjustment.
- North America > United States (0.93)
- South America > Argentina > Neuquén Province > Neuquén (0.48)
- Geology > Geological Subdiscipline (0.93)
- Geology > Petroleum Play Type > Unconventional Play (0.67)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.50)
- South America > Argentina > Patagonia > Neuquén > Neuquen Basin > Vaca Muerta Shale Formation (0.99)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.94)
- North America > United States > Texas > Permian Basin > Yates Formation (0.94)
- (28 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Gas-injection methods (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
- Production and Well Operations > Artificial Lift Systems > Gas lift (1.00)