bluuebunny/crossref_metadata_2025_split huggingface dataset:
Early Detection of Fault Activation Using Surface Tilt Monitoring During a CO2 Injection Project
Authors: Salimzadeh S. , Kasperczyk D. , Chen Z. , Movassagh A. , Arjomand E. , Mow W. S. , Kear J. 
Published: September 2022

ABSTRACT:
Tracking the migration of injected CO2 is critical to understanding the performance of subsurface intervals selected for CO2 sequestration. Measuring and analyzing the shape and magnitude of the surface deformation caused by subsurface CO2 injection, provides confidence that sequestered CO2 will remain in the target formations. Surface deformation information for onshore injection operations can be obtained via InSAR satellite imagery or an array of high-resolution tiltmeters installed in shallow (10-15m deep) boreholes.
In this study, synthetic tilt data produced from a full 3D finite element model of the In Salah CO2 injection site, are used to determine the shape and location of the CO2 plume at the three injection wells. A strong tilt signal (&gt;0.1μRad) can be observed well ahead of the equivalent detectable surface heave (&gt;2 mm, typical InSAR limitation magnitude). The inverse analysis for an array of ten tiltmeters around each of three injection wells clearly shows whether the injected CO2 remained in the target layer or leaked into a nearby fault. Results show that tracking the tilt vectors on the top of the fault can inform the operators of the onset of the fault pressurization.

1. INTRODUCTION
Geological storage of carbon dioxide in the deep subsurface was identified as one of the key technologies for reducing the emission of greenhouse gases to the atmosphere and mitigating global warming and climate change (Baines & Worden, 2004; Hepple & Benson, 2005; Schrag, 2007). The types of geological reservoirs suitable for large-scale, long-term subsurface storage of CO2 mainly include deep saline aquifers, existing oil and gas fields, and deep unmineable coal seams. There are major concerns on the large-scale injection of CO2 into these geological formations and the long-term storage security such as injection induced reservoir stress and deformation, CO2 plume migration and leakage, well integrity, caprock sealing performance, potential fault reactivation and notable seismic events (Rutqvist et al., 2015). Effective modelling and monitoring of geological CO2 injection and storage are therefore essential to better understanding of the mechanisms of the storage process, to the development of reliable geological carbon storage technologies and their successful implementation (Adriana Paluszny et al., 2020; Saeed Salimzadeh et al., 2018).
Dynamic Fracture Conductivity Considering Stress-Deformation Behavior of Proppants in Shale Formation
Authors: Wang Qiqi , Chen Mian , Wang Su 
Published: September 2022

ABSTRACT:
Most of the artificial fractures formed by fracturing need to be injected an appropriate amount of proppant into the fractures to achieve long-term support and maintain a stable fracture opening. Under the action of closing stress, the fracture wall and proppant will undergo a dynamic deformation process. Based on the Hertz elastic contact theory, this study establishes a two-dimensional finite element model of the contact deformation between the proppant sphere and the fracture plane. The model uses the spring as the medium to define the contact pair between them, and analyzes the stress interference phenomenon between the proppants. The smaller the proppant particle size, the smaller the gap between adjacent spheres, the stronger the inter-particle interference, and the strained regions are connected, which is close to a semicircle. The larger the particle size, the easier the embedding of the proppant will lead to the uneven wave shape of the fracture surface. Whether a large amount of proppant is embedded globally or locally has a particular influence on the dynamic evolution of the stress field, it is necessary to consider whether such agglomeration effect occurs when studying subsequent fracture opening and effective propping.

1. INTRODUCTION
There were several constraints confronted in the field during the hydraulic fracturing process. One of the main issues faced was the closure of the newly fractured area, limiting the future extraction of gas (M.A.A Ahamed, 2019). Proppants were utilized in hydraulic fracturing applications as a countermeasure to fracture closure due to the high in-situ stress at deep unconventional rock deposits (C.T. Montgomery, 1985). Several studies evaluating the fracking process have shown that effective stress and several other factors can lead to proppant rearrangement, proppant diagenesis, and proppant embedment, which can significantly reduce the hydraulic conductivity (M. Mehdi Mollanouri Shamsi, 2016).
Many scholars conducted laboratory studies on proppant embedment. The effects of elastic modulus, closure pressure, water saturation, particle size and distribution, proppant concentration, and fluid viscosity were investigated (Volk et al., 1981; R. Hartley et al., 1985; Lacy, L.L. et al., 1997; Lacy, L.L. et al., 1998; Qingzhi Wen et al., 2007; 9. Zhang, Junjing, et al., 2015). However, the disadvantage of experimental research was that there were many rock types, complex reservoir environments, and specific use scenarios for proppant types, sizes, and concentrations, so it is difficult to obtain general conclusions. The shape of the proppant was generally spherical particles, and due to the difference in its size, the fracture face can be regarded as a semi-infinite plane. Therefore, theoretical research can be abstracted as the contact deformation problem of spherical particles and the semi-infinite plane.
The Conductivity of Proppant and Impacts of Proppant Flowback on Fracture Conductivity in Different Conditions
Authors: Wang Bin , Zan Jingge , Liang Tianbo , Pan Zhikun , Liu Sen , Zhou Fujian 
Published: September 2022

ABSTRACT:
Hydraulic fracturing can increase the fracture conductivity by providing high-conductivity channels for hydrocarbon flow. Proppants flow back from the propped fracture during the early stage of production in the hydraulically fractured tight reservoirs, during which the fracture conductivity decreased due to the proppant flowback. In this paper, the conductivity of the proppant is quantified at different concentrations and closure stresses as baselines. Then, flowback experiment is conducted to understand the impacts of flowback rates, fracturing fluids, closure pressures, and proppant placement methods. When the pressure is higher than 40 MPa, the fracture conductivity of paving with sand will approach zero due to the crushing of sand under the high closure pressure, while the ceramic proppant has high conductivity due to a low crushing rate. The conductivity gradually decreases with time, during which the decline rate is large at the initial stage, and decreases with time till reaching a plateau. When the slickwater is used, the daily production of 70— 200 m3/d in conventional horizontal wells can reduce sand production. When the guar is used, the critical flow rate is expected to be doubled due to the guar residues after gel breaking. Proppant size has a larger impact on proppant flowback than the fracturing fluid. Combined proppant can also decrease the proppant flowback. It is found both fracturing fluids residue and special proppant paving methods can reduce the proppant flowback, which can guide the choke sizes in field conditions.

1. INTRODUCTION
Hydraulic fracturing is used for shale reservoir stimulation to get more daily production to solve the problems of low natural productivity and difficult waterflood development due to the shale formation characteristics of small pore throat radius and low permeability. The proppant is pumped into the fractures to support artificial fractures in the hydraulic fracturing to create the hydrocarbon migration channel. The high conductivity of fractures is the guarantee of enhancing oil recovery in shale reservoirs. (Cohen et al., 2013; Gomaa et al., 2014)
An Experimental Study of CO2 Huff-N-Puff Enhanced Oil Recovery in Three Forks Formation, Williston Basin
Authors: Sennaoui B. , Pu H. , Rylander E. , Afari S. , Malki M. L. 
Published: September 2022

ABSTRACT:
The primary oil recovery in the Bakken Petroleum System is still small, with a range of 5% to 12% of the original oil in place (OOIP). This study aims to investigate the potential and the performance of CO2 injection with HnP on the recovery factor (RF) in Upper Three Forks (UTF) and Middle Three Forks (MTF) formations, Sanish Field, Williston Basin, North Dakota (ND). In order to achieve this purpose, a series of laboratory experiments were applied where the performance of cyclic CO2-EOR was evaluated under different scenarios of injection with various operational conditions. Different parameters were considered to understand the mechanisms of HnP CO2-EOR, including the pressure of injection above and under the minimum miscibility pressure (MMP), the effect of soaking time on production, and several injection cycles to maximize the oil recovery. Then a comparison of the performance of CO2-EOR with ethane (C2) and propane (C3) under the same operating condition to evaluate the feasibility of different gases in the HnP approach. In addition, X-ray diffraction mineral analysis (XRD) was performed on four samples taken from UTF and MTF to determine the mineral composition in both formations. The results showed that the most recoverable formation was UTF with 56% of RF during the first cycle, while MTF showed only 37%. Increasing the number of cycling from one to four cycles showed that RF increased up to 88% and 75% in UTF and MTF, respectively. In addition, injection pressure seems to have a significant effect on RF in both formations, where the results showed that increasing the pressure from 800 Psi to 3600 Psi improved RF from 15% and 16% to 56% and 37% in UTF and MTF, respectively. Moreover, increasing the soaking time from 4 hrs to 48 hrs, RF increased from 37% and 25% to 72% and 39% in UTF and MTF, respectively. The results from comparison of different gases injections showed that, with injection pressures of 3600 Psi and soaking time of 24 hrs, ethane was the most effective gas in both formations, followed by propane and CO2, respectively. In conclusion, CO2 HnP has good potential in the lab and can be a promising method in unconventional reservoirs. This research work may provide an improved understanding of the CO2 HnP enhanced recovery strategy for unconventional reservoirs.
Molecular Simulation of Adsorption and Diffusion Behavior of CO2 in Bakken Nano-Porous Media for Enhanced Oil Recovery Assessment
Authors: Bellal Abdelmalek , Assady Ailin 
Published: September 2022

ABSTRACT:
The use of molecular simulation to quantify gas adsorption and diffusion is needed to study the CO2 Enhanced Oil Recovery (EOR) efficiency. Favoring CO2-Oil interaction over CO2-Rock interaction depends on the strength of the interaction bond between CO2 and nanopores surface. In this study, we explored the effect of pore size and reservoir temperature on CO2 adsorption and diffusion behavior in Bakken. This comprehensive study covers the characterization of Bakken CO2-EOR using grand canonical Monte Carlo and molecular dynamic simulations. The results indicated that increasing reservoir temperature would reduce the amount of adsorbed CO2 and the adsorption kinetics of CO2 into Bakken nanopores follows a first-order Langmuir model. CO2 adsorption in Bakken nanopores was strong at low temperatures and large pore sizes. Also, high CO2 injection pressures (e.g., 55MPa) led to strong diffusion of CO2 into the nanopores. This is undesirable as high CO2 adsorption and diffusion into the walls of the nanopores would cause molecular loss of the injected CO2, consequently lower EOR efficiency. The insights gained from this work might help improve theoretical understanding of the micro behaviors of CO2 in Bakken reservoir nanopores and give valuable recommendations in CO2-EOR.

1. INTRODUCTION AND BACKGROUND
In 2021, North Dakoda contributed to US oil production as second-ranked with production over 1MMbscf. Although using advanced technologies of hydraulic fracturing in unconventional reservoirs such as Bakken made higher oil production possible, the recovered production oil is only 2% of the Bakken original oil in place (OOIP). Also, maintaining production is quite challenging in unconventional reservoirs. Thus researchers are exploring the flow mechanisms to sustain oil production, including developing several enhanced oil recovery (EOR) methods such as gas injection and CO2 EOR for improving the recovery factors over the past few decades. Based on the experimental and numerical studies, one of the potential methods with a promising indication of oil incremental is CO2 EOR (Jia et al., 2018; Thakur, 2019). During a CO2 injection process, oil recovery factor can increase as a result of CO2-oil interaction. Injected gas can swell the oil and reduce viscosity leading to higher oil mobility. Also, the underground injection of captured CO2 from combustion stations has the benefits of reducing greenhouse gas emissions which makes CO2 injection a valuable process. (S. Wang, 2016). On the other hand, CO2 injection processes are not always in favor of increasing oil recovery due to the adsorption of CO2 in rock. Moreover, there is always a gap between field and simulation-predicted oil recovery (Jia et al., 2018). Therefore, it is important to investigate the effect of some common assumptions in tight reservoirs such as the ignorance of the diffusion flow mechanism and adsorption to improve oil recovery prediction.
Prediction of Shear Wave Velocity in the Williston Basin Using Big Data Analysis and Robust Machine Learning Algorithms
Authors: Laalam A. , Mouedden N. , Ouadi H. , Chemmakh A. , Merzoug A. , Boualam A. , Djezzar S. , Aihar A. , Berrehal B. E. 
Published: September 2022

ABSTRACT:
The shear velocity is one of the most critical parameters in determining the mechanical rock elastic properties, which serve as inputs for different studies such as wellbore stability, mechanical earth modeling, hydraulic fracturing, and reservoir characterization. However, the sonic log is not acquired in every drilled well. We analyzed the log data of more than 35000 wells in the Williston Basin, and we found that only very few wells had sonic logs. For this reason, several studies attempted to correlate the shear velocity (or slowness) to other easily accessible properties; these will be presented in the literature review, with their pros and cons.
The focus of this paper is to apply machine learning algorithms to synthesize the shear slowness log. Our models are trained and tested with log data from 27 wells drilled in the Bakken petroleum system, Williston Basin. Logging data include Gamma Ray, Deep Resistivity, Density, Neutron Porosity, and Shear Slowness. Five different algorithms were developed and tested against blind data including Xtreme Gradient Booster, Random Forest Regressor, Linear Regression, Ada Boost Regression, and Bayesian Ridge Regression. Overall, the R2-score varied from 0.55 to 0.92, with the XGBoost outperforming the other algorithms.

1. INTRODUCTION
With more than a century of oil and gas production, companies have generated a tremendous amount of data with every drilled well and field operation. These data banks are either unused or poorly analyzed. While the proper technical analysis of this could improve the performance of the oil and gas industries significantly.
In the past, the focus of researchers and engineers was to develop efficient tools and methods to acquire necessary data. With the advances in computational power, companies realized that they could take advantage of the data more efficiently. The application of artificial intelligence (AI) and specifically machine learning (ML) along with big data analytics have known an enormous surge.
Characterizing Rock Fractures and Physical Properties for Experiment 2 of the EGS Collab Project, Sanford Underground Research Facility
Authors: Ulrich C. , Dobson P. F. , Kneafsey T. J. , Roggenthen W. M. , Uzunlar N. , Doe T. W. , Neupane G. , Artz T. , Dobler K. , Schwering P. , Smith M. , Burghardt J. A. 
Published: September 2022

ABSTRACT:
The EGS Collab project is focused on understanding and predicting permeability enhancement and evolution in crystalline rocks to support geothermal energy production. To support this effort, the project is creating a suite of intermediate-scale test beds coupled with stimulation and interwell flow tests that will provide a basis to better understand the fracture geometries and processes that control heat transfer between rock and stimulated fractures. Therefore, high level site characterization is paramount for building models to estimate potential interwell flow rates and heat exchanges. For the second experimental testbed, the EGS Collab team visually mapped the distribution, orientation, and nature of open and healed fractures exposed along the drift wall in the Sanford Underground Research Facility 4100 feet below ground surface, and within the eleven boreholes drilled for this test bed. Continuous core logging of each borehole and a suite of geophysical wireline logs was collected to characterize the spatial variability of rock properties and fracture orientations. All of the data were then compiled into multiple 3D visualization software packages for interpretation and further analyzed for slip and dilation tendencies that will be incorporated into coupled-process geomechanical flow and transport models to better constrain the planned flow and tracer tests.

1. INTRODUCTION
Following the completion of Experiment 1 at 4850 feet below ground surface (the 4850 level), the EGS Collab team initiated the development of a second testbed for Experiment 2 (E2) in the Sanford Underground Research Facility (SURF and former Homestake Gold Mine) in Lead, South Dakota, USA. The overarching goal of the EGS Collab project is to create field test beds to host stimulation and interwell flow tests that will provide improved understanding of fracture stimulation methods, resulting fracture geometries, and processes that control heat transfer between rock and stimulated fractures for Enhanced Geothermal Systems (EGS). This experiment will contrast from Experiment 1 in that its goal is to create a series of hydro shear fractures for interwell flow tests in support of the EGS Collab project (Kneafsey et al., 2018) at the intermediate-scale (~10-20 m). In the winter-spring of 2021, the EGS Collab team started to develop the E2 testbed on the 4100 level (1.25 km below the ground surface).
Evaluation of NATM Tunnel Cutting Face in Japan Using Machine Learning
Authors: Halim K. D. , Yun Y. , Kusumi H. 
Published: September 2022

ABSTRACT:
In Japan, the determination of support patterns (CI, CII, DI, DII) in NATM tunnels plays an important role in the construction of mountain tunnels. Conventional methods of rock mass evaluation include grading the rock by experienced experts with a point-based system in 9 criteria as regulated by the Ministry of Land, Infrastructure, Transport and Tourism (MLIT). However, discrepancy in judgement by these experts based on field experiences and subjective standards means that the current method of evaluation is ambiguous. Therefore, this research proposes a standardized evaluation method by verifying the applicability of machine learning to rock surface evaluation. Support vector machine (SVM) is implemented to build the model for the classification of four support patterns based on data collected from different tunnel construction sites. As a result, the proposed model has shown high accuracy. Furthermore, by taking into account the current system of evaluation of the tunnel cutting face, the classification accuracy significantly improved. Thus, the proposed model has shown strong candidacy as a standardized evaluation method.

1. INTRODUCTION
At mountain tunnels constructed using NATM (New Austrian Tunnel Method), the property of rocks found in mountains such as the type, strength, etc. of the rock mass determines the class of the rock itself. During the tunnel’s design stage, support patterns are determined in accordance with the classified rocks to prevent the mountain from collapsing. The tunnel cutting face is then observed and support patterns are changed accordingly in the construction stage to maximize safety and minimize costs. Furthermore, additional construction methods may be required when the initial support constructions are deemed insufficient based on these evaluations.
The former method of evaluating the rock of the tunnel cutting face is by observing and measuring the strength, discontinuity, etc. of the rock surface. Based on these observations, the tunnel cutting face is graded using a point-based system. However, the criteria for these evaluations were subjective and evaluation methods differed by engineer even if it was the same tunnel cutting face that was observed.
Numerical Simulation of Rock Breaking Mechanism Analysis of Drill Bit with Central Stinger in Axial Percussive Drilling
Authors: Wang Xinrui , Zhang Hui , Ma Xusheng , Zhou Yuting , Li Youyi , Lu Zongyu 
Published: September 2022

ABSTRACT:
The drill bit with central stinger element assisted by axial vibration has achieved a good rate of penetration in granite and diorite formation in China, but the study on the theoretical rock breaking mechanism of this bit is still insufficient. To better understand the rock-breaking mechanism of drill bit with central stinger and provide a theoretical basis for practical engineering, this paper presents numerical modelling with the finite element method of dynamic cutting processes under 50-200Hz loads. The rock breaking model with three 16mm plain cutters and a 16mm central stinger cutter is established, the cutters break a certain depth of granite at the fixed weight on bit and rotate speed. The rock failure mode, cutting force, mechanical specific energy (MSE) is analyzed and then compared with the steady load breaking condition. Also, the influence of cutter’s location has been analyzed and results indicate that, for 16mm cutter, when the cutting radius of the first plane cutter is less than 13.1mm, there is almost no cutting force on stinger cutter. When the radius is greater than 13.1mm, the force on stinger cutter always increases with the increase of the radius and exists a maximum value. Compared with the steady load, the average cutting force and MSE of stinger cutter under 100Hz load decrease by 11%. Meanwhile the fluctuation of the cutting force of stinger and other three cutters are significantly smaller, the maximum cutting force is reduced by over 19%, which reduces the occurrence of stick-slip. The findings contribute to understand theoretical rock breaking mechanism of central stinger bit, also optimize the bit selection and percussive drilling parameters.

1. INTRODUCTION
In drilling operation of petroleum engineering, the Polycrystalline Diamond Compact (PDC) bits are becoming much more widely used and important tools for directional wells, extended reach wells, deep wells and even the ultra-deep wells due to its good efficiency and economy of being able to repair. Nowadays the PDC bits have dominated almost all the footages in drilling operation of oil and gas wells, the efficiency of PDC bits has become a key part of the economics of the drilling operation (Cheng et al., 2018, 2019; Zhang et al., 2020). Therefore, the methods to design efficient and durable PDC drill bits have become the most important direction in drill bit development.