Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
Collaborating Authors
Western Canada Sedimentary Basin
ABSTRACT Hydraulic fracturing is crucial for enhancing hydrocarbon production from unconventional reservoirs. The characterization of fracture geometry and propagation has significant value in understanding reservoir response and designing more efficient completions. Distributed acoustic sensing (DAS) is a rapidly developing technology that can be used for this purpose because it provides wide-aperture observations of microseismic wavefields that contain direct P and S arrivals as well as converted and reflected waves. In addition to traditional approaches for microseismic event location and source mechanism analysis, the high spatial resolution of DAS microseismic recordings allows the imaging of induced fractures with reflected waves. Reflections are generated by waves radiated from microseismic events that impinge on hydraulic fractures created during prior treatment stages. We use a straightforward method based on f-k filtering and ray tracing to map reflected S waves from the time domain to reflectivity in the space domain. A case study of fracture imaging indicates that inferred fracture development, based on reflection imaging, is consistent with fracture-driven interactions observed using low-frequency DAS (LF-DAS) data. In addition, this study reveals reflection images of apparent distal fractures that do not reach the fiber and thus are not directly observed by LF-DAS. Fracture images obtained from several microseismic events during the same stage provide the opportunity to observe snapshots of dynamic fracture evolution processes.
- North America > Canada > British Columbia > Western Canada Sedimentary Basin > Alberta Basin > Montney Formation (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Montney Formation (0.99)
Abstract Since the early 2000s, the exploitation of unconventional reservoirs has become very important to the oil and gas industry because of their high potential source of energy and economic value. Venezuela possesses a world-class hydrocarbon source rock in one of the most prolific hydrocarbon basins in the world, namely the Cretaceous La Luna Formation in the Maracaibo Basin. Outcrop and core samples collected from the northwestern Maracaibo Basin provide the database for this study. A comprehensive multiscale characterization of the samples is undertaken to unravel the stratigraphic properties of the petroleum system. In addition, a geochemical approach is taken to evaluate the prospectivity of the La Luna Formation as an unconventional resource in the Maracaibo Basin. Rock-Eval pyrolysis and biomarker data indicate that the La Luna Formation is dominated by type II kerogen, indicating an oil-prone marine organic matter origin. Total organic carbon values range between 3.85ย wt% and 9.10ย wt%. Distributions of isoprenoids, steranes, and terpanes including gammacerane and monoaromatic steroid hydrocarbons indicate a hypersaline, marine carbonate anoxic depositional environment. Thermal maturity parameters indicate that most of the cores are currently in the oil window. This combined stratigraphic geochemical study indicates that the La Luna Formation has excellent potential as an unconventional reservoir for oil and gas in the study area.
- Phanerozoic > Cenozoic (1.00)
- Phanerozoic > Mesozoic > Jurassic (0.92)
- Phanerozoic > Mesozoic > Cretaceous > Upper Cretaceous (0.67)
- South America > Venezuela (0.99)
- South America > Colombia > Middle Magdalena Basin > La Luna Shale Formation (0.99)
- South America > Colombia > Aguardiente Formation (0.99)
- (17 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Geochemical characterization (1.00)
Abstract Serial-sectioned images were three-dimensionally reconstructed to visualize the fracture network within an outcropped cube, sourced from the Montney Formation, the largest unconventional natural gas resource in Canada, that was hydraulically fractured in the lab under conditions similar to real field operations. Following the experiment, the fractured cube was saturated with fluorescent materials to distinguish the fracture network from the rock matrix and provide common spatial references for a modified serial-sectioning and photographing method using ultraviolet light. The obtained serial-sectioned images underwent image processing, distortion removal calibration, and image registration for three-dimensional visualization, including reconstruction and segmentation. The results highlighted the significant influence of bedding planes and rock anisotropy on the generated fracture network geometry. These observations have important implications on the evaluation of the stimulated rock volume, as well as on completion strategies, as preferential opening of bedding planes might result in horizontal intra-well connectivity and increase parent-child interactions.
- North America > Canada > Alberta (0.67)
- North America > Canada > British Columbia (0.50)
- North America > Canada > Ontario > Toronto (0.15)
- North America > Canada > Saskatchewan > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- North America > Canada > Northwest Territories > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- North America > Canada > Manitoba > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- (3 more...)
Abstract The expanding global population and clean energy demand suggests utilizing renewable energy from sources such as wind, solar, biomass, geothermal, hydro and biofuel. The intermittent nature of such sources has propelled a need for efficient storage. Hydrogen (H2), being a carbon-free energy carrier, emerged as a potential solution, but it will require large volume to be stored to meet the demand. Underground hydrogen storage (UHS) is preferred given its low cost, tightness, and safety. Although existing UHS facilities have safely operated for over 40 years, the expected demand growth will require frequent injection-withdrawal cycles. This review provides an examination of the processes involved during H2 cycling. Firstly, the different cyclic tests are classified based on loading path, frequency, type and environment conditions. Then the behavior of rock salt under cyclic loading is discussed. Detailed attention is given to the chemical interaction between H2 and salt, covering experimental research concerning UHS in salt caverns. The review ends by presenting a laboratory experimental workflow involving the coupled processes within UHS operations.
- North America > Canada > Alberta (0.28)
- Asia > Middle East > Saudi Arabia (0.28)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Mineral > Halide > Halite (0.70)
- North America > Canada > British Columbia > Western Canada Sedimentary Basin > Alberta Basin > Montney Formation (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Montney Formation (0.99)
- Asia > China > Sanshui Basin (0.99)
Static Modelling and Fault Seal Analysis of the Migrant Rollover Structure, Sable Subbasin, Offshore Nova Scotia, Canada
Martyns-Yellowe, K. T. (Basin and Reservoir Lab, Department of Earth and Environmental Sciences, Dalhousie University) | Richards, F. W. (Basin and Reservoir Lab, Department of Earth and Environmental Sciences, Dalhousie University) | Watson, N. (Atlantic Petrophysics Limited, Nova Scotia) | Wach, G. D. (Basin and Reservoir Lab, Department of Earth and Environmental Sciences, Dalhousie University)
Abstract Crestal faulting can lead to breach of trap integrity and leakage. The Migrant structure is an example of a potentially breached trap due to fault leakage and juxtaposition. In this paper we use 3D geocellular modeling, populated with new interpretation of input parameters, including shale volume, to examine the possible mechanism for leakage (crestal faulting). A fault plane profile (Allan diagram) was constructed, which can be taken a further step into dynamic modelling and simulation (not presented in this study). Located in the Sable Sub-basin, the Migrant structure is a fault controlled, four-way dip anticlinal closure, which formed as one of a series of related structures during rift basin extension, sediment loading and salt mobilization in the Cretaceous. Genetically related rollover structures (e.g., the Distal Thebaud Field) in a similar structural and stratigraphic setting have proved viable as a commercial trap. The Migrant N-20 well was drilled to test for hydrocarbons trapped in Late Jurassic to Early Cretaceous deltaic and fluvial-deltaic reservoirs in the structure. The well encountered gas from a deep sand reservoir during drill stem testing (DST 2) with a reported flow rate of 10 million standard cubic feet per day. However, over the duration of the test, an associated decline in flow rate and pressure depletion was observed, which led the operators to consider the target reservoir as non-commercial. In this paper we present a re-appraisal to assess why this trap failed by integrating well data (logs, checkshot and pressure) and 3D seismic to produce a static model demonstrating the trapping mechanism in the Migrant Structure. Initial observation of the 3D seismic shows shallow crestal faults while preliminary observation of well logs from the Migrant N-20 well suggests a diminishing sand/shale ratio from the shallow to deep sections of the trap. This study of the Migrant Structure contributes to the understanding of the relationship between reservoir and seal thicknesses relative to fault displacement and its role in subsurface fluid trapping or cross-fault leakage, through upward and outward displacement (stair-stepping) between reservoirs of different ages across a given fault. The paper shows how data integration and workflows have been combined effectively and is an important contribution for risk assessment in the Sable Subbasin. The proposed model can be applied in other basins including the similar salt cored basins like those offshore Brazil.
- North America > Canada > Nova Scotia > North Atlantic Ocean (0.88)
- North America > Canada > Newfoundland and Labrador > Newfoundland > North Atlantic Ocean (0.28)
- Phanerozoic > Mesozoic > Jurassic > Upper Jurassic (0.48)
- Phanerozoic > Mesozoic > Cretaceous > Lower Cretaceous (0.48)
- Geology > Structural Geology > Tectonics (1.00)
- Geology > Structural Geology > Fault (1.00)
- Geology > Sedimentary Geology > Depositional Environment (1.00)
- (4 more...)
- Geophysics > Seismic Surveying > Surface Seismic Acquisition (1.00)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Seismic Processing (0.93)
- (3 more...)
- Oceania > New Zealand > East Coast Basin > PEP 38348 (0.99)
- North America > Canada > Saskatchewan > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- North America > Canada > Nova Scotia > Scotian Slope > Missisauga Formation (0.99)
- (18 more...)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Sedimentology (1.00)
- (5 more...)
Abstract Most reported carbon storage projects have involved inexpensive CO2 capture from gas processing plants or ethanol refineries. However, widespread carbon capture and storage application must avoid any risk that high capital investment cost for carbon capture from stationary point sources leads to unanticipated issues related to the aquifer storage. This paper reviews successful and unsuccessful carbon storage projects and explains simple extended aquifer system fundamentals that must be considered in selecting a storage aquifer. This study begins by evaluating reported carbon storage projects in the context of an extended aquifer system with specific attention to initial formation pore pressure and potential or known hydraulic vertical or lateral communication with hydrocarbon accumulations and/or fresh water. Further study focusses on how the contrast between injection well and aquifer pressure evolution enables understanding of the overall aquifer material balance. Finally, we consider implications of brine migration during and after long term CO2 injection in unconfined aquifers. Experience in the petroleum industry with aquifer behavior include presence or lack of water influx and production from hydrocarbon reservoirs that share a common aquifer. Of particular importance is the observation that hydrostatic initial formation pressure indicates the possibility that a petroleum system, or an extended aquifer system without hydrocarbon accumulation(s), connects to atmospheric pressure through an unconfined aquifer. In such cases indefinite injection will never increase the regional aquifer pressure. Further, initial formation pressure that exceeds hydrostatic pressure implies a petroleum system or an extended aquifer system that is volumetrically limited. In such cases injection will increase the system pressure, and pressure monitoring can detect leakage from the system. Finally, CO2 injection into an aquifer will displace brine in the direction of lower pressure that could relate to distant production from the same aquifer or from hydrocarbon reservoirs with which it communicates. Reasons for known carbon storage project interruptions have included unexpected lateral plume migration or aquifer pressure increase during CO2 injection that might have been anticipated with attention to straightforward consideration of aquifer enabled hydraulic communication. Such extended aquifer dynamics must be included in long term models for permanent CO2 storage during and after injection.
- North America > United States (1.00)
- Europe > Norway > Barents Sea (0.93)
- North America > Canada > Alberta (0.68)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.47)
- North America > United States > Kentucky > Illinois Basin (0.99)
- North America > United States > Indiana > Illinois Basin (0.99)
- North America > United States > Illinois > Illinois Basin (0.99)
- (84 more...)
The Multiple Bedding Planes (BPs) Effect on Fracture Height Propagation: Experimental Study and Field Data Analysis
Shuai, Li (Research Institute of Petroleum Exploration and Development, PetroChina, Beijing, China) | Bo, Cai (Research Institute of Petroleum Exploration and Development, PetroChina, Beijing, China) | Dingwei, Weng (Research Institute of Petroleum Exploration and Development, PetroChina, Beijing, China) | Chunming, He (Research Institute of Petroleum Exploration and Development, PetroChina, Beijing, China) | Xinbin, Yi (Oil and Gas and New Energy Company, PetroChina, Beijing, China) | Haifeng, Fu (Research Institute of Petroleum Exploration and Development, PetroChina, Beijing, China)
Abstract Geological structures such as pre-existence of multiple bedding planes (BPs) significantly influence the hydraulic fracture height propagation in shale gas and shale oil reservoirs. Field engineers have also proved that fracture height is much lower than designed via monitoring such as microseismic and DTS/DAS test. In this paper, hydraulic fracturing simulation is studied by injecting fluids into a 1mร1mร1m rock-block sample with multiple thin BPs developed at the in-situ stress condition, and during the operation process, acoustic emission (AE) monitoring is used to obtain the fracture propagation events. After the fracturing physical simulation, we cut the rock sample from three different perspectives and take visual observation of the fracture geometry via fluorescence irradiate. Secondly, we carried out series field data analysis such as fracturing curve history matching, flow-back data analysis and production data analysis, aiming to find the correlation between fluids leak-off rate, flow-back salt concentration, fracture height, fracture complexity and the number of BPs. Results showed that fracture propagation is a competition controlled by stresses and rock BPs. Fracture propagation is generally perpendicular to minimum principal stress while is locally controlled by the rock BPs. It always initial to be vertical fractures near the wellbore area, while as the vertical fracture penetrates the BPs, fracturing fluids would leak into the BPs and form horizontal fractures, lead to slow propagation in height direction and change the final fracture geometry. Fluorescence irradiate also showed fracture propagation can be divided into three modes, directly penetrate the BPs, arrested by the BPs or bifurcate into BPs, and these are mainly depending on the high-angle natural fractures. The results of this study suggest that a significant portion of fracturing fluids could be retained in BPs, which in turn is the reason of fracture height propagation obstruction. In field data analysis, we find that fluids leak-off rate has positive correlations with BPs number, fracture complexity and hydrocarbon production. Flow-back salt concentration (salinity) also has positive correlation with BPs number while has negative correlation with fracture height. Ratio of fluids leak-off and fracture height (Vleak/Hf) or ratio of flow-back salt concentration and fracture height (Cf/Hf) can be used as evaluating indicators for the number of BPs that fracture penetrates through. Experimental study and field analysis of the BPs effect on fracture height propagation can provide constructive guide for the hydraulic fracturing of BPs developed reservoirs.
- North America > United States (1.00)
- Asia > China (0.95)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
Case Study of Successful Pilot Polymer Flooding to Improve the Recovery of Lloydminster Heavy Oil Reservoir- West Central Saskatchewan
Ulovich, Ivan (Cenovus Energy Inc) | Imqam, Abdulmohsin (ZL Chemicals Ltd) | Martinez, Juan (Cenovus Energy Inc) | Aljubori, Ahmed (ZL EOR Chemicals Ltd) | Rathod, Rakeshkumar (Cenovus Energy Inc)
Abstract The Lloydminster Heavy Oil Block is the main source of Canada's conventional heavy oil production. The most common methods of recovery in this area are primary production, waterflooding, and chemical-enhanced oil recovery (EOR) such as polymer flooding. Although heavy oil waterfloods could be relatively successful if managed properly, their production and economic efficiencies are often challenging due to quick water breakthrough followed by a steep decline in oil production. Beliveau (2009) showed that over 50% of oil produced from such water flood projects are typically produced at water cuts greater than 90%, which would increase water processing costs. The objective of this study is to outline the implementation of a successful polymer flood project in Lloydminster Heavy Oil Block that includes the production and injection performance of the pilot. It also describes the steps of selecting the appropriate polymer type based on reservoir rock properties, water quality, and other main parameters for the optimal polymer selection. An anionic polymer candidate provided by ZL EOR Chemical Ltd. was selected for the project. The field under study is in the province of Saskatchewan and producing from the Lloydminster sandstone. Initially, the field was produced under a line drive waterflood with horizontal wells. The reservoir has a live oil viscosity of about 2,600 cP at downhole temperature of 21.5ยฐC and the average clean-sand permeability of 1,500 mD. In April 2018, a polymer flood pilot was introduced as a primary recovery method with continuous polymer injection at ~25 cP (~2000 ppm polymer concentration). Injection rates varied from 30 to 50 m/d/well, based on the target injection volume of 5 to 10% of effective pore volume (PV) per year. As a result, field water cut has decreased and stabilized at ~65%, while oil production rate has remained relatively constant at ~40 m/d for over five years with no signs of polymer breakthrough. Production performance from the beginning of the polymer flood demonstrates the efficiency of this EOR method, thereby providing valuable insights into the first primary polymer flood project in the Lloydminster Heavy Oil Block.
- North America > Canada > Saskatchewan (1.00)
- North America > Canada > Alberta (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Geological Subdiscipline (1.00)
- South America > Suriname > North Atlantic Ocean > Guyana-Suriname Basin > Tambaredjo Field (0.99)
- South America > Guyana > North Atlantic Ocean > Guyana-Suriname Basin > Tambaredjo Field (0.99)
- North America > Canada > Saskatchewan > Western Canada Sedimentary Basin > Alberta Basin > Dina Formation (0.99)
- (7 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Abstract Canadian crude oil and pigged wax from the Montney formation show high wax appearance temperatures (WAT) and experience severe deposition issues during production and transportation. Several commercial wax inhibitors and wax dispersants were studied in the crude oil and reconstituted oils (pigged wax added back to the crude oil and dodecane model system), to minimize the wax deposition by a systematic lab screening protocol. Suitable wax inhibitors (WI) and dispersants were selected and formulated at optimized dosage to efficiently reduce the wax deposition at close to field condition. The crude oil and reconstituted oils were utilized to study the high WAT wax performance with different types of wax inhibitors and dispersants. This included ethylene vinyl acetate (EVA), alkylphenol formaldehyde resin (AFR), acrylic copolymer (AC), ฮฑ-olefin maleic anhydride copolymer (AOMAC) and several surfactant-based wax dispersants (WDs). A pour point tester was employed as the initial screening tool to determine the pour point and detected wax appearance temperature (DWAT). Multiple Light Scattering (MLS) was used to evaluate the dispersions of wax in the oil. Dynamic wax deposition tests by capillary flow through (CFT) and dynamic flow loop (DFL) systems were used to verify the wax deposition reduction efficiency, and to study the effect of the test parameters on wax deposition. The reconstituted oils had higher WAT (>55 ยฐC) than produced oil. The screening tests showed that EVA significantly reduced the DWAT and pour point of the crude oil but was not very efficient in the reconstituted oil. Both AFR and AC reduced the DWAT and pour point but were not as efficient as AOMAC. AOMAC provided the lowest DWAT in the reconstituted oil. It was interesting to find that surfactant-based dispersants also reduced the DWAT of the reconstituted model oil. The top performing WIs and dispersants were then tested by CFT wax deposition system at a flowrate of 1.5 cm3/hr. For the crude oil at 10 ยฐC, 225 ppm AOMAC WI was needed to efficiently reduce the wax deposition in the CFT system. A lower dosage was required in the DFL system. It was also found that wax inhibitor and dispersant together further reduced the reconstituted model oil wax deposition in the CFT system. MLS and bottle tests showed that the WDs helped to disperse the wax in both oil and aqueous phases. From this systematic WI study on kinetic and dynamic behaviors of high WAT wax deposition, a synergy was observed between wax inhibitors and dispersants. Further investigation is needed to understand how they work together. The specially designed laboratory screening protocol helped to understand the structure and performance relation, efficiently formulate the WIs/dispersants, and optimize the treatment dosages. The inclusion of surfactants/dispersants with WIs could further mitigate wax deposition and be a more cost-effective approach.
- North America > Canada > Alberta (0.48)
- North America > United States (0.46)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > Canada > British Columbia > Western Canada Sedimentary Basin > Alberta Basin > Montney Formation (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Montney Formation (0.99)
First Challenging Geothermal Well for Carbon Neutral Campus
Gustafson, O. (Cornell University, Ithaca, New York, USA) | Bezner, W. (Cornell University, Ithaca, New York, USA) | Ibrahim, A. (SLB, Houston, Texas, USA) | Jafri, A. (SLB, Houston, Texas, USA) | Barton, L. (SLB, Houston, Texas, USA) | Reyes, A. (SLB, Houston, Texas, USA) | Poroli, M. (SLB, Houston, Texas, USA)
Abstract Cornell University is exploring the direct use of geothermal energy as a sustainable energy source to heat its Ithaca campus. The Earth Source Heat (ESH) project is an essential component of Cornell University's solutions to achieve carbon neutrality by 2035. The project's first phase included drilling a 3-kilometer-deep exploration well to collect subsurface data from the deep sedimentary and crystalline basement rock formations. These data will inform the design and specifications for creating an "enhanced geothermal system" comprised of a network of open fractures that will serve as a heat reservoir for a demonstration well pair, injecting cool water and producing hot water to heat Cornell University's campus in the cold New York winter. The engineering design of the project's first phase involved many challenges, from selecting optimum casing seats with minimum offset well information to overcoming potential subsurface risks related to drilling through a thick salt formation and highly unstable shales. Which were taken into consideration during the design phase. The Engineering team, along with Cornell University's scientists, collaborated in the design phase and utilized innovative engineering solutions on a cloud-based platform for optimizing the well design. This design was coupled with a dedicated mechanical earth model study for the well to reduce the mud window uncertainty. Each component of the well design was analyzed to ensure optimum design practices and safe operational limits based on an extensive risk assessment of all potential hazards along with prevention and mitigation plans. For the execution phase, the engineering team utilized a state-of-the-art digital solution for drilling automation and optimization, where drilling dysfunctions such as shock and vibrations and variable formation hardness were displayed in a real-time advisory mode for drilling performance optimization. The well construction phase was a continuous, agile process between the well engineering team and the University's scientists to achieve the project's challenging goals.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.37)
- Geology > Mineral > Halide > Halite (0.35)
- Geophysics > Seismic Surveying (1.00)
- Geophysics > Borehole Geophysics (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Energy > Renewable > Geothermal > Geothermal Resource (0.34)
- Energy > Renewable > Geothermal > Geothermal Direct Use (0.34)
- North America > United States > West Virginia > Appalachian Basin > Utica Shale Formation (0.98)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Field > Marcellus Shale Formation (0.98)
- North America > United States > Virginia > Appalachian Basin > Marcellus Field > Marcellus Shale Formation (0.98)
- (10 more...)