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Collaborating Authors
SPE/AAPG/SEG Unconventional Resources Technology Conference
Abstract One of the greatest challenges facing the development of unconventional shale resource systems by drilling horizontal wells in factory mode is the definition of the optimal spacing between wells and the appropriate stimulation design that allow maximizing the volume of hydrocarbon recovered while minimizing the cost of field development. The Vaca Muerta formation in the Neuquén basin of Argentina is considered an unconventional shale play where the economic production of hydrocarbons has been proven through drilling and stimulation of horizontal wells. To quantify the vertical and horizontal interferences between horizontal wells targeting different landing zones and estimating their effective drainage height, production allocation by geochemistry, chemical tracers, pressure interference analysis, and well performance techniques were integrated into several well pads in the oil and gas window. Introduction Since the ‘80s, geochemical approaches have been used to solve reservoir and production problems in the oil and gas industry (Larter et al. 1994, Larter and Aplin 1995). These applications are known as reservoir and production geochemistry (allocation) and are based on the recognition of significant compositional differences between the fluids corresponding to each of the producing layers (vertical heterogeneities) or in different areas of the reservoir (lateral heterogeneities). Case studies with these applications have been documented in the main productive basins of the world and the geochemical allocation methodology has been successfully applied locally in Argentina in the Chihuido de la Sierra Negra – Lomitas, Señal Cerro Bayo and Auca Mahuida Volcano fields in the Neuquén basin (Labayén et al. 2004 and 2005) and Manantiales Behr, Cañadón La Escondida, Cañadón Perdido, Central Zone and Los Perales fields in San Jorge Gulf basin (Fasola et al. 2005 and 2008). However, for unconventional shale reservoir plays, there are precedents published only in the United States (McCaffrey et al. 2011 and 2016; Liu et al. 2017; Jweda et al. 2017; Kornacki et al. 2017, among others) and just one publication for the Vaca Muerta formation (Fasola et al. 2022).
- South America > Argentina > Patagonia Region (1.00)
- South America > Argentina > Neuquén Province > Neuquén (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (1.00)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.46)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.47)
- South America > Argentina > Patagonia > Neuquén > Neuquen Basin > Vaca Muerta Shale Formation (0.99)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- (39 more...)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale oil (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Management > Energy Economics > Unconventional resource economics (1.00)
Integrated Petrophysical Characterization of Hydrocarbon Shale Unconventional Reservoirs Using a Rock Typing Approach, Case Study, Vaca Muerta Play, Neuquén Basin, Argentina
Panesso, Rafael (Inter Rock Colombia) | Quaglia, Alfonso (Inter Rock USA) | Alzate, Guillermo (Universidad Nacional de Colombia) | Porras, Juan (Inter Rock Venezuela)
Abstract Hydrocarbon shales represent a challenge in both their petrophysical characterization, as well as in determining the feasibility for their economic development. For a correct characterization, it is important to define the intrinsic characteristics of the formation about its potential to contain and deliver hydrocarbons, as well as the ideal zones in the formation to stimulate by hydraulic fracturing that guarantees the initiation, propagation and maintenance of fractures. As main objective, a workflow was developed to create a unique index, called the unconventional rock type index (URT_Index), to classify unconventional rock types. This index allows the evaluation of the development potential for these types of reservoirs. This index is generated from the integrated analysis of geochemical, mineralogical, petrophysical, acoustic and geomechanical information, through a geometric association based on the properties of the rock, representing a combination of characteristics related to the productive potential of the rock, which in turn will serve as a guide to design the completion strategy. For the definition of the URT_Index, properties such as total organic carbon content, total porosity, hydrocarbon saturation and brittleness index were considered, all of which can be calculated from conventional logs and calibrated with laboratory measurements. The results demonstrated that from the defined rock types it was possible to differentiate prospective zones, define usable net thickness and show a good correlation to production performance. It was observed that the distribution of the perforated intervals in the completion stages corresponded to the most fragile rock types that would guarantee the propagation of fractures and an efficient connection with zones of interest. The URT_Index agreed with the rock type classification based on the geometric association by more than 95%, demonstrating that the index satisfactorily reproduced variations in rock properties. The URT_Index can play an important role in the comprehensive ranking of the prospects by identifying both the quality of the reservoir and the zones with the best potential for fracturing. An advantage of the URT_Index is it is a practical method that can be applied in many of the reservoirs of this type that may lack special logs and/or core laboratory measurements.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.73)
- South America > Argentina > Patagonia > Neuquén > Neuquen Basin > Vaca Muerta Shale Formation (0.99)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- (13 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- (4 more...)
Nano-Surfactant Packages for Enhanced Oil and Gas Recovery in Hydraulic Fracturing-Impact on the Nano-Sizers on the Performance of Conventional Surfactants
Kakadjian, Sarkis (NexTier Oilfield Solutions) | Flowers, Amanda (NexTier Oilfield Solutions) | Kitchen, Jarrett (NexTier Oilfield Solutions) | Gebrekirstos, Amanuel (NexTier Oilfield Solutions) | Boyd, Kristopher (NexTier Oilfield Solutions) | Algadi, Otman (NexTier Oilfield Solutions)
Abstract Surfactant packages have been known to enhance the post-treatment clean-up of stimulation treatments from hydraulic fracturing. When used this way the surfactant packages are known as flowback aids. These additives reduce the completion fluid loss from the fracture surface to the formation by assisting the return of trapped fluids in the wellbore and reservoir to the surface. Nano-surfactant packages have also been reported to create somewhat their equivalent mechanism of performance and benefit to the application. The current work shows the development of flowback recovery aids based on Nano-Surfactants packages from currently used surfactant technology and their actual impact in the Permian when compared both technologies within in the same formation. Nano-Surfactants have been formulated with current surfactants packages by the introduction of nano-sizers. The performance of the different formulations has been evaluated by different methodologies including monitoring the changes on the size of the micelles by light scattering. Those formulations that once diluted in brackish and/or produced water showed size of the micelles below 100 nanometers (nm), were then rated by interfacial tension with crude oils from Wolfcamp formations. Over 25 formulations were evaluated and those that passed the size screening and after showed the lowest interfacial tensions were then analyzed using the column load recovery and oil recovery by spontaneous imbibition tests. The results of the study showed that for those selected conventional surfactants reformulated with the nano-sizer to generate the equivalent Nano-Surfactant versions, not only managed to drop the size of the micelles well below the 100 nm mark but also reduced the interfacial tension down to 10 mN/m to enable faster load recovery by up to 84% and the oil recovery by up to 227% per spontaneous imbibition in the amott cells - all tested with Wolfcamp Cuttings and Outcrops samples and crude oils from the Wolfcamp-A and B. As additional observation, the selected Nano-Surfactants showed general trend to lower emulsification of crude oil in the lab as well in the field not always guarantee with their conventional surfactant versions. The chemical solutions implemented in the Permian using the formulated Nano-Surfactant versions, managed to increase the barrel of oil equivalent (BOE) in average perforated feet from 26 bbl/ft with the conventional surfactants to 34 bbl/ft with the Nano versions in the Upper Wolfcamp for the first 12 months of production with a marginal cost increase.
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- North America > United States > Texas > Permian Basin > Midland Basin (0.99)
- North America > United States > Texas > Permian Basin > Delaware Basin (0.99)
- (5 more...)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid management & disposal (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (0.84)
- Well Completion > Completion Fluids > Completion fluids (0.75)
Abstract This work presents a novel framework to quantify the variability in hydraulic fracture geometry in a multi-cluster multi-stage hydraulic fracturing treatment well using stage-by-stage Instantaneous Shut-in Pressure (ISIP) analysis. The fundamental Sneddon’s equation is used to develop a mathematical solution that accounts for poroelastic stress shadow effects and lateral geomechanical heterogeneity, which leads to non-uniformity in hydraulic fracture height and length distribution along the horizontal well. Additionally, a separate solution is proposed for calculating the hydraulic fracture half-length in a multi-stage multi-cluster horizontal well using the fundamental solution of the Perkins, Kern, and Nordgren (PKN) fracture. It will be demonstrated that this computationally efficient approach can reasonably replicate the stage-by-stage hydraulic fracture geometry with minimal cost and is in good agreement with microseismic monitoring and fracture modeling results. Introduction Hydraulic fracturing (HF) is a widely used technique in the oil and gas industry to enhance production from tight hydrocarbon-bearing formations, such as coal beds, shales, mudstones, and tight sandstones. This process involves pumping a highly pressurized fluid mixed with sand and chemicals into the well at high rates to create permeable conduits in the rock (Economides and Nolte, 2000). To ensure the success of this process, it is crucial to understand the hydraulic fracture geometry, including their half-length and height. This information allows operators to optimize hydraulic fracturing treatment design and achieve the desired production results. Accurately predicting and modeling hydraulic fracture geometry can be challenging due to several factors, such as complex stress regimes in subtly different geological and geomechanical environments as well as subsequent fracture interactions in multi-cluster, multi-stage fracture jobs created from different benches of a multi-well pad (Warpinski, 2008; Mayerhofer, 2011). Hydraulic fracturing diagnostics are widely used to gather crucial data during the fracturing process to optimize well productivity. The most commonly employed fracturing diagnostics include microseismic monitoring, fiber optics, tracers, pressure, and rate transient analysis. While microseismic and fiber optics diagnostics offer in-depth insights into the geometry of the fracture, including its shape, size, and orientation, they require specialized equipment, expertise, and are expensive to execute. Despite these challenges, combining information obtained from these diagnostics with advanced fracture modeling techniques and data analysis can improve future fracturing operations (Cipolla et al. 2010).
- North America > Canada > British Columbia (1.00)
- North America > Canada > Alberta (0.95)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.54)
- 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...)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Well Completion > Hydraulic Fracturing > Multistage fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Information Technology > Modeling & Simulation (0.66)
- Information Technology > Data Science (0.48)
Abstract This work aims to emphasize the importance of making an adequate structural interpretation in high complexity areas, with its consequent impact on the design of the development plan of an unconventional reservoir. Also present a new approach for the development of Vaca Muerta Fm. in a Field at early stages of development. The methodology of structural characterization consisted of interpreting the kinematics of the faults present in the area, analyzing their extension and activity for the different geological times of each landing zones within Vaca Muerta Fm. Influence of active faults on the thickness and properties of the reservoir was analyzed. The structural activity between the different fault systems could have affected the depositional environment and especially the conditions of preservation of organic matter (dilution). This would explain why, in wells located in positions where there was greater structural activity, the total organic carbon (TOC) values are lower than in more stable areas. Considering the structural interpretation and the petrophysical characteristics of the reservoir, the full-field development plan was carried out, with a maximum of four landing zones to be developed. Subsequently, it was decided to apply a novel Monolayer development strategy for Vaca Muerta, starting with the most productive level identified in the area, Unit 1, in the less structurally complex zone. The main technical challenges faced by this type of development were analyzed, such as 3D drilling geometries, surface limitations in pads to develop multiple levels of navigation, potential increase of casing deformation risks, among others. Introduction The study area is in the shale oil core sector of Vaca Muerta Fm. located in the Neuquén Basin (Figure 1) and at 90 km from the Neuquén city. In this position the Quintuco-Vaca Muerta system has an average thickness of 700 m. It presents four levels of unconventional interest that have been tested in sectors where no structural risks were visualized.
- Geology > Structural Geology > Fault (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.61)
- Asia > Middle East > Israel > Southern District > Eastern Mediterranean Basin (0.99)
- South America > Argentina > Patagonia > Neuquén > Neuquen Basin > Vaca Muerta Field > Vaca Muerta Shale Formation (0.98)
- North America > Canada > Alberta > Black Field > Acl Black 10-17-111-9 Well (0.93)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (0.94)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale oil (0.84)
- Management > Asset and Portfolio Management > Field development optimization and planning (0.69)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (0.66)
Abstract Traditional assessment of "free" oil-in-place via programmed pyrolysis can be challenged due to false positives (OBM invasion/interference), non-unique signatures (i.e. low temperature shoulders) or biased from sample handling procedures (unpreserved or ‘vintage’ core/cuttings). Additionally, estimated oil saturations and volumetrics of producible hydrocarbons from core material may be underrepresented if certain extraction practices are used. Here, we utilize an advanced thermal extraction technique that is tailored to optimize mobile bulk volumes of oil within a target horizon. Further geochemical assessment of the collected thermal extract aids in additional understanding of the hydrocarbons in place (source/maturity/migration). Retort oil evaluation via fine-tuned thermal extraction techniques can significantly increase estimated oil saturations and oil in place calculations. It’s important to note that the selected retort temperature regime for Formation X in Basin A may very well be different than Formation Y in Basin B due to variations in source rock (kerogen) type, thermal maturity and/or a number of other factors. Therefore, a tailored experimental set up for a specific formation of interest would provide the dataset with the highest confidence for saturation and producibility evaluations. Introduction When evaluating the geochemical makeup of hydrocarbons within a rock (core/SWC/cuttings/etc.), it is important to understand the effects that the chosen extraction technique has on the fluid that is being extracted. For instance, when using excess solvent in a Soxhlet or Dean Stark apparatus, the solvent must be evaporated off to concentrate the extract before analysis. During that evaporation phase, light- to mid-chain hydrocarbons (typically up to ∼nC15), which were potentially present in the parent rock sample, would also be lost before analysis even begins. If extraction of the heavier hydrocarbons was the goal, a solvent-based approach is appropriate but if light- to mid-chain hydrocarbons are dominant or if accurate original oil in place (OOIP) estimations are needed, then the loss of such hydrocarbons should be avoided.
- North America > United States > Texas (1.00)
- North America > United States > Colorado (0.94)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.34)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.75)
- North America > United States > Wyoming > Uinta Basin (0.99)
- North America > United States > Wyoming > Laramie Basin > Niobrara Formation (0.99)
- North America > United States > Utah > Uinta Basin (0.99)
- (10 more...)
Reactive Transport Modeling of Anthropogenic Carbon Mineralization in Stacked Columbia River Basalt Reservoirs
Cao, Ruoshi (Energy and Environment Directorate, Pacific Northwest National Laboratory) | Muller, Katherine A. (Energy and Environment Directorate, Pacific Northwest National Laboratory) | Miller, Quin R. S. (Energy and Environment Directorate, Pacific Northwest National Laboratory) | White, Mark D. (Energy and Environment Directorate, Pacific Northwest National Laboratory) | Bacon, Diana H. (Energy and Environment Directorate, Pacific Northwest National Laboratory) | Schaef, H. Todd (Energy and Environment Directorate, Pacific Northwest National Laboratory)
Abstract Numerical simulation of CO2 storage in basalts and related reactive lithologies requires modeling complex, coupled hydrologic and chemical processes, including multi-phase flow and transport, partitioning of CO2 into the aqueous phase, and chemical interactions with aqueous fluids and rock minerals. We conducted reactive transport simulations of the Wallula pilot-scale CO2 injection into the flow tops of the Grande Ronde Basalt using our Pacific Northwest National Laboratory STOMP-CO2 simulator with the ECKEChem reactive module. Our mineralization simulation of the ∼1,000 tons of injected CO2 into the interflow zones was based on the hydrologic transport model we previously developed. For this work, the simulations considered geochemical reactions involving the basalt components, precipitates, formation brine, and injected CO2. In our benchmark case, carbonate minerals precipitated, resulting in ∼20% of the CO2 being mineralized in 10 years. Increasing the reaction rate of a single primary mineral phase (clinopyroxene) by an order of magnitude resulted in a carbon mineralization reaction extent of ∼90% over the same time interval. Based on these initial sensitivity analysis results, it is clear that a thorough understanding of primary mineral dissolution rates is required for accurately predicting long-term fate and transport of injected CO2 into basalt formations. Our reactive transport numerical simulations will be key components of commercial-scale CO2 storage operation permitting, de-risking, and optimization in mafic and ultramafic reservoirs. Introduction In 2009, the Wallula Basalt Pilot project was initiated with the drilling of a CO2 injection well to a depth of 1,253 m below ground level (bgl) at the Boise White Paper Mill property at Wallula, Washington. The well intersected three deep layered basalt flowtops starting at 830 m (Figure 1) that received ∼1,000 tons of CO2 in August of 2013 over three weeks. After 24-month, sidewall cores were extracted from the injection zone as part of an extensive post-injection characterization champaign. Laboratory analysis performed on the retrieved core identified anthropogenic carbonate mineral assemblages (e.g. ankerite, aragonite, and siderite) that were isotopically, texturally, and chemically linked to the injected CO2 (Depp et al., 2022; McGrail et al., 2017a; McGrail et al., 2017b; Polites et al., 2022). Recently, our detailed analysis of pre-injection and post-injection hydrologic testing in the context of a robust hydrogeologic Wallula model indicated that ∼60% of the injected CO2 mineralized in only two years (White et al., 2020). The objective of this present study is to numerically simulate the CO2 transport and reactivity at Wallula and determine how predicted carbon mineralization rate determinations compare with our recent carbon mineralization quantification (White et al., 2020), laboratory results, and field data.
Abstract The available seismic data often does not provide a resolution that allow for precise landing point and lateral control when drilling horizontal wells. This will leaving a high dependency to the closest well data available. Moreover, subtle stratigraphic and structural features are often not imaged properly by the available seismic data due to resolution limits. These features sometimes important to understand for supporting well planning and avoiding drilling hazards. This study demonstrates how ConocoPhillips uses an inhouse proprietary technology to improve seismic resolution for supporting landing zone, hazard determination and attribute extractions for reservoir quality mapping and distribution without any requirement for re-acquisition or complete re-processing. The methodology, Seismic Super Resolution (SSR), is described as a post-imaging inversion which is inspired by super resolution techniques from computer vision. The technology imposes a sparsity/coherency assumption on geophysical parameters by formulating a constrained minimization problem to get a higher-resolution volume from the original data. The method is independent from well data to avoid any bias, but a validation process using synthetic well data is applied to justify the result before using it for an interpretation. The product of this technology is a higher resolution seismic dataset that allows for more precise landing point and lateral control when drilling horizontal wells. The product also allowed for interpreting increasingly subtle stratigraphic and structural features. Subtle faults which were not interpretable with the original seismic dataset, within the reservoir section, became clear on this higher resolution seismic data. Spatial delineation of mass transport complexes, which are significant for reservoir quality distribution, is also improved after SSR was applied to the original seismic dataset. This study demonstrates a novel and cost-effective post imaging seismic inversion technique adapted from computer vision that shows clear value for drilling to stimulation planning and risk mitigation in the Delaware Basin. This technique also allows ConocoPhillips to better characterize reservoir distribution which beneficial for field development planning.
- North America > United States > Texas (0.75)
- North America > United States > New Mexico (0.64)
- North America > United States > Mississippi > Marion County (0.24)
- Geophysics > Seismic Surveying > Seismic Processing (1.00)
- Geophysics > Seismic Surveying > Seismic Modeling > Velocity Modeling > Seismic Inversion (0.69)
- North America > United States > Texas > Permian Basin > Delaware Basin (0.99)
- North America > United States > New Mexico > Permian Basin > Delaware Basin (0.99)
The Impact of Thermal Maturity on the Organic-Rich Shales Properties: A Case Study in Bakken
Malki, Mohamed Lamine (University of Wyoming / Los Alamos National Laboratory) | Rasouli, Vamegh (University of Wyoming) | Mehana, Mohamed (Los Alamos National Laboratory) | Mellal, Ilyas (University of Wyoming) | Saberi, Mohammad Reza (Geosoftware) | Sennaoui, Billel (University of North Dakota) | Chellal, Hichem A. K. (University of North Dakota)
Abstract Organic-rich shale characterization in Bakken shales is complex due to the heterogeneity and ambiguity of rock properties, including mineral composition and petrophysical properties such as porosities and fluid saturations. In addition, the dependence of the reservoir properties on the thermal maturity of the formation adds more complexity to the characterization. Consequently, it is crucial to quantify the impact of thermal maturation on the reservoir properties for accurate reservoir characterization. We provide a quantitative assessment of thermal maturity on geological features and petrophysical properties. We focused on two productive zones in the Williston Basin, McKenzie and Divide Counties, with different maturation levels, rock properties and total organic carbon (TOC) wt%. Note that a fully representative mineral composition of Bakken requires many inputs due to its multimineral characteristic. Therefore, we derived a correlation between various minerals and applied it to the computed mineralogical model. Furthermore, source rock, petrography, and fluids characterizations were estimated to determine the potential of hydrocarbon generation for production purposes. We also estimated maturity-induced porosity based on Alfred & Vernik (2012) approach, where more representative properties are used to study the development of kerogen porosity. The quantification of the generated organic porosity helps to better assess the reservoir quality, which is crucial to identify the productive zones, especially during drilling and hydraulic fracturing operations, to maximize the recovery. Introduction The Bakken formation in the Williston Basin is one of the largest tight oil-bearing reserves in the U.S. and has been a field study for various oil recovery enhancement strategies and technologies (Harju et al., 2023b; Ozotta et al., 2022a; Sennaoui et al., 2023; Sorensen et al., 2010). It currently has an estimated 10 to 500 billion barrels of oil in place. However, its ultra-low permeability, porosity characteristics, and heterogeneous mineralogy require careful development, completion, and production strategies to maximize recovery (Afari et al., 2022; Aoun et al., 2023a; Aoun et al., 2023b; Merzoug et al., 2022; Sennaoui et al., 2022a; Sennaoui et al., 2022b; Sorensen et al., 2010). Regarding its lithology characteristics, Bakken mainly consists of lower (LB) Bakken, Upper (UB) source rocks, and middle (MB) members that are proven reservoirs. UB and LB have similar lithology and are composed of black organic-rich mudstone, with total organic carbon (TOC) content that may reach 40 wt%, whereas MB units vary widely from siliciclastic to carbonate, with different diagenetic trends that involve irregular dolomitization of carbonate sections (Laalam et al., 2022; Malki et al., 2022a; Smith & Bustin, 2000).
- North America > Canada > Saskatchewan (1.00)
- North America > Canada > Manitoba (1.00)
- North America > United States > North Dakota > Divide County (0.27)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- North America > United States > Texas > Haynesville Shale Formation (0.99)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > United States > South Dakota > Williston Basin > Bakken Shale Formation (0.99)
- (12 more...)
Abstract We propose an efficient coupled flow and geomechanics simulation that utilizes multi-resolution grids based on Diffusive Time-of-Flight (DTOF). This work generalizes the Fast Marching Method (FMM) - based flow simulation developed for unconventional reservoirs (Chen et al., 2022) to coupled flow and geomechanics simulation. The proposed multi-resolution simulation workflow significantly reduces the computational time for the coupled simulation while accounting for the complex flow around hydraulic fractures and the resultant pressure and stress evolution associated with hydrocarbon production. The FMM-based simulation discretizes the reservoir by grouping fine-scale cells based on DTOF contours, where the DTOF represents the arrival time of the propagating pressure front that can be efficiently computed by solving the Eikonal equation using FMM. Our proposed approach solves both flow and mean-stress based geomechanics equations (Hu et al., 2013; Winterfeld et al., 2015) on the DTOF grids assuming that contours of pressure and mean-stress change are aligned with the DTOF contours. This assumption is shown to be reasonable under most circumstances. For balancing accuracy and efficiency, the original fine-scale grids are retained around wells and connected to 1-D DTOF grids via non-neighbor connections to form a multi-resolution grid system. The FMM-based coupled flow and geomechanics simulation has been validated with 3-D fine-scale flow and geomechanics simulation, where the FMM-based multi-resolution simulation produces almost identical results. This paper focuses on development of the efficient coupled simulation workflow for 3-D field-scale application to predict pressure and stress evolution, and subsidence caused by pressure depletion associated with production in unconventional reservoirs. To facilitate field-scale application while taking advantage of the complex underlying physics, commercial flow simulator is coupled with in-house geomechanics simulator using one-way coupling. The proposed multi-resolution modeling approach in conjunction with the simplified geomechanics simulation has significant computational advantage when compared to conventional 3-D finite element-based geomechanics simulation due to reduced primary variables and computation nodes. The FMM-based coupled flow and geomechanics simulation is a novel approach to speed up coupled simulation which has been hindered by excessive computation time.
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.46)