bluuebunny/crossref_metadata_2025_split huggingface dataset:
Effect of CO2 on Mineralogy, Fluid, and Elastic Properties in Middle Bakken Formation Using Rock Physics Modeling
Authors: Malki M. L. , Rasouli V. , Saberi M. R. , Sennaoui B. , Ozotta O. , Chellal H. 
Published: September 2022

ABSTRACT:
The Bakken Petroleum System in the Williston Basin consists of three main members: Upper Bakken Shale (UB), Middle Bakken (MB), and Lower Bakken Shale (LB). The Middle Bakken is a calcareous siltstone and fine-grained sandstone which is a proven reservoir within the Williston Basin. Injection of Supercritical CO2 (ScCO2) may cause changes in the elastic behavior of the rock and therefore may reactivate the fault in the Bakken Formation. This research aims at studying the changes in the MB mechanical properties when flooded with ScCO2 for 30 days, and to quantify the physical and chemical effects of ScCO2 saturation on the mineralogy composition and fluid properties of the formation. This will be achieved using different rock physics models before and after ScCO2 injection. Two different samples were taken from MB clastic and carbonate portions of well 24123 in McKenzie County. X-Ray Diffraction (XRD) analysis was applied on two samples pre-and post-CO2 saturation. The results of post-CO2 modeling resulted in a decrease of densities and elastic properties of both lithologies at different rates. Only change in mineralogy and fluid properties were considered for the post-CO2 injection modeling.

1. INTRODUCTION
The Bakken formation consists of three main members: Upper Bakken Shale (UB), Middle Bakken (MB), and Lower Bakken Shale (LB). The UB and LB shales are proven source rocks with a similar lithology and are composed of an organic-rich, siliceous, pyritic black shale. The UB covers a larger areal extent than the LB within the Williston Basin. The MB member is a calcareous siltstone and fine-grained sandstone which is aproven reservoir within the Williston Basin (Lefever & Helms, 2006; Nordeng et al., 2010; Pitman et al., 2012). Despite the enormous hydrocarbon reserves within the Bakken formation, the Bakken is classified as unconventional oil-bearing reservoir due to its ultra-low porosity and permeability characteristic (Sorensen et al., 2008). The variation of MB lithology across the Williston Basin from mainly clastic to carbonate led to divide it intoseven distinct lithofacies (Lefever & Helms, 2006; LeFever & LeFever, 2005; Ozotta et al., 2021c).
A Rock Mechanical Experimental Study on the Effect of Hydrostatic Pressure and Directional Stress on Rock Sample Permeability
Authors: Almakrami A. H. , Alqam M. H. , Algarni S. H. 
Published: September 2022

ABSTRACT:
The objective of this study is to compare the laboratory sensitivity of the permeability of cylindrical plugs to variations in hydrostatic and directional stress to determine how different stress evolution trajectories may affect fluid flow for different rock types. To achieve this, series of Stress-Dependent Permeability (SDk) tests were performed on suites of rock mechanical plugs, covering a wide range of lithology and permeability, employing different types of transients simulating varying geo-mechanical conditions during loading and/or unloading processes. Specific laboratory testing procedures were adapted depending on the permeability of the rock sample. Steady-state method was deployed for medium to high permeability samples, while complex transient (subjecting a sample to a pressure pulse and monitor the resulted pressure decay) methods were deployed to estimate the permeability of tighter rock samples. Test results suggest that plug samples with low to ultra-low permeability are more sensitive to changes in hydrostatic pressure, and less affected by directional stress variations. For more permeable samples, permeability responses to a dynamically evolving state of stress may exhibit a degree of sensitivity to directional stress variations difficult to predict without conducting a proper laboratory analysis.

1. INTRODUCTION
In some cases, during the production cycle of a reservoir, the net effective reservoir stress is increasing due to reduction of the pore pressure; this continuous process induces an alteration of the reservoir flow capacity of the reservoir. Published studies (Fatt, 1952) showed that while the change in porosity with pressure is small, the effect of overburden stress is significant on permeability. Another study (Jones, 1979) showed that tight sand samples are profoundly affected by evolving net reservoir stress more than the permeable samples. Moreover, the effect of changing stress environment has been investigated on different formations, i.e. sandstone and carbonates (Dautriat et al, 2007) to accentuate a relationship between effective stress and permeability. In this lab study, we are attempting to investigate the stress-dependent permeability in tight and medium-to-high permeability rock samples, in response to the effect of both hydrostatic pressure and directional stress, aiming to program the relationships between hydrostatic pressure and directional stress in order to optimize permeability and maximize fluid flow.
A Machine Learning-Based Microseismic Event Location and Wave Velocity Prediction
Authors: Maksut Z. , Meiramov R. , Yazici A. , Suorineni F. 
Published: September 2022

ABSTRACT:
Human-induced seismicity from underground mining can have a huge effect on the safety, productivity, and operating costs of mines. Hence, the mining industry demands an accurate predictor for microseismic source locations in order to mitigate unexpected catastrophes such as rockbursts. The aim of the research is to use machine learning models to predict real-time seismic wave velocities in the constantly degrading underground mine environment. In underground mining, the rockmasses and voids are constantly changing in quality, geometry, and content with mining. Data for this study is generated by a research team at the laboratory of the School of Mining and Geosciences at Nazarbayev University. The research on the application of machine learning is also conducted at the School of Engineering and Digital Sciences in the same university. The main findings of the data analysis were that due to the heterogeneity and constant change of the mining environment, the seismic wave velocity is not constant, hence the traditional methods of calculating the event source location using a constant velocity model in the seismic monitoring systems will often lead to inaccurate results. The accuracy of determining seismic event source locations depends on the seismic wave velocity assumed in the algorithm for the event source location. Thus, the ability to predict real-time seismic wave velocity allows the better location of seismic events. Several machine learning approaches have been explored for the prediction of seismic wave velocities under various conditions. Linear Regression models were trained from the data obtained in the laboratory to predict the wave velocity. The deep learning approach was also used to achieve higher precision, in particular, Deep Artificial Neural Networks (ANN) have been applied. Compared with Linear Regression which could only learn linear relationships between the features and the target, Deep ANN could learn complex relations due to the activation function in each layer.
Numerical Investigation of Geopolymer Displacement in an Enlarged Wellbore: Implications for Wellbore Integrity
Authors: Wu Yuxing , Salehi Saeed , Khalifeh Mahmoud 
Published: September 2022

ABSTRACT:
Cement-mud displacement plays a crucial role in the sealability of cement sheaths. An unstable interface between two fluids always leads to mud channeling, interfluid mixing, and cement contamination and degrades the cement quality. In this study, a 3D computational fluid dynamics (CFD) model is developed to simulate the time-dependent mud removal in a horizontal casing-formation annulus. The annulus geometry is created based on the caliper log data from an unconventional shale well in the Tuscaloosa Marine Shale (TMS). A water-based mud (WBM) is displaced by i) neat class G and ii) rock-based geopolymer, respectively. The results present that geopolymer has a lower residual mud resulting in a lower risk of cement failure. Cement slurries injected with a high flow rate cause better displacement performance. Reducing density ratio causes few residual drilling fluids in the annulus due to buoyancy effects. Compared with the density ratio, the flow rate has a lower sensitivity on the cement volume fraction. The model can be extended to any other mud-slurry displacement procedure as the annulus geometry and the properties of the drilling fluid and cement slurry are known.

1. INTRODUCTION
Cement sheath is an important barrier to maintaining wellbore integrity, preventing formation fluids from flowing into an unintended area. After setting a casing into an openhole, the cement slurry is injected into a target depth to displace the annulus’s original drilling fluids (mud). The cement is drying from a slurry to a solid, developing a set cement. A recent study estimated that 13% of loss well control accidents in the past resulted from cement failure during drilling and 30% occurred during production (Patel et al., 2019a). The failure could lead to costly and complicated remedial operations and trigger environmental contaminations (i.e., groundwater contaminations). An excellent cement design should satisfy the requirements of long-term and short-term well integrity. The long-term design considers structural failures of the cement sheath in the form of circumferential cracking, axial cracking, debonding, shear failure, and cement crushing (Patel et al., 2019b; Wu et al., 2020a, 2021; Kimanzi et al., 2020). Short-term integrity factors such as cement slurry quality, rheology, and pumpability during cementation are the major considerations (Bittleston et al., 2002; Maleki and Frigaard, 2017; Kimanzi et al., 2019; Etrati and Frigaard, 2019; Foroushan et al., 2021).
Linking Microscale Processes to Macroscale Salt Creep with a New THMC Model
Authors: Hu M. , Steefel C. I. , Rutqvist J. 
Published: September 2022

ABSTRACT:
Microscale grain deformation and reorganization, fracturing, and pressure solution at interfaces have been identified as the mechanisms for the creep of salt at larger scales. However, it remains uncertain how each mechanism quantitatively impacts creep in granular salt that are naturally under complex geometric and multi-physical conditions. In this study, we have developed a new microscale thermal-hydro-mechanical-chemical (THMC) model that accounts for coupled deformation, dynamic contacts, chemical reaction, and fluid transport in heated environment in granular systems where the microscale geometry can be realistically represented. The THMC model was achieved by linking a microscale mechanical code based on the numerical manifold method (NMM) to the reactive transport model Crunch. Using this first-of-its-kind microscale model, we show the results of compaction within a halite aggregate. We found that sharp corners of salt grains can dominate the contact dynamics, microfracturing, and pressure solution, thus governing the porosity loss of the system. We show that pressure solution and structural changes can be further accelerated by a thermal gradient due to changes of thermodynamics and reaction rates. We show that grain reorganization and pressure solution can occur repeatedly and continuously, thus contributing to longer-term creep of salt at larger scales.

1. INTRODUCTION
Understanding the creep of salt is essential for effectively predicting the long-term evolution of nuclear waste repositories and strategic storage caverns for oil and gas in salt rocks (Urai et al., 1986). Different underlying mechanisms of creep in different stress/temperature ranges have been theoretically proposed (Urai et al., 1986). Based on laboratory tests micrograph, Urai and Spiers (2007) suggested that grain dislocation, microfracturing and pressure solution (Spiers et al., 1990; Zhang et al., 2007) are mechanisms acting during long-term creep. Identifying these mechanisms has advanced the understanding of salt creep. However, an important scientific question remains:
How does each mechanism quantitatively impact creep in granular systems that involve such complex geometric and multi-physical conditions?
The Influence of Failure Criterion on the Estimation of In-Situ Stress Using the Wellbore Breakout of Inclined Well
Authors: Peng Hao , Tang Zhiqiang , He Mingmin , Chen Yousheng , Gao Jiajia , Chen Yifan 
Published: September 2022

ABSTRACT:
The accurate information of in-situ stress at depth is critical for oil and gas drilling and hydraulic fracturing operations. The technique of estimating the maximum horizontal stress using the wellbore failure detected from imaging logging has been widely recognized, but the influence of different rock failure criteria on the calculation results has always been neglected. Therefore, according to the linear poroelastic mechanics theory and different failure criteria of rock, the maximum horizontal stress in southwest Sichuan of China is calculated using the wellbore breakout of an inclined well from literature. The calculation results show that magnitudes of the maximum horizontal stress calculated with different failure criteria vary greatly. The frequent earthquakes in southwest Sichuan indicate that the preexisting faults in this area are close to the friction limit state under the in-situ stress, which agrees well with the results calculated by using Mogi-Coulomb criterion.

1. INTRODUCTION
In-situ stress is very important for oil and gas drilling and hydraulic fracturing stimulation operations. Accurate knowledge of stress magnitude and orientation can help us to design reasonable drilling fluid density and borehole trajectory for preventing wellbore failure and associated underground complexity. Wellbore shape reflects the stress state that the wellbore wall is being or has been subjected. Thus, according to the wellbore shape and drilling history data, we can determine the stress distribution around the wellbore wall and calculate the magnitude of the in-situ stress. Although the final shape of wellbore may be different from the shape after the initial wellbore breakout, the breakout width remains unchanged (Zoback et al., 1985; Barton et al., 1988). Therefore, the breakout width can reflect well the initial stress state of wellbore when breakout occurs.
Many authors preferred using wellbore failures to calculate the in-situ stress, even established several models to calculate the maximum horizontal stress combining Mohr-Coulomb criterion (Barton et al., 1988; Vernik & Zoback, 1992; Zoback et al., 2003; Frydman & Ramirez, 2006), but these models are only suitable for the failures of vertical wellbore. Peska and Zoback (1995) also adopted Mohr-Coulomb criterion to determine the maximum horizontal stress magnitude according the wellbore failure of inclined well. However, the effect of intermediate principal stress on rock strength is ignored in Mohr-Coulomb criterion, which may lead to unrealistic calculation results of in-situ stress. Although Tang et al. (2021) chose Mogi-Coulomb criterion in the analysis of the influence of thermo-poroelastic coupling operation on the calculation results of in-situ stress, the author did not analyze the differences caused by other criteria, which may have significant influence on in-situ stress estimation.
Parent-Child Well Interaction in Multi-Stage Hydraulic Fracturing: A Bakken Case Study
Authors: Merzoug A. , Chellal H. A. K , Brinkerhoff R. , Rasouli V. , Olaoye O. 
Published: September 2022

ABSTRACT:
Multi-stage hydraulic fracturing technology for enhanced production from unconventional reservoirs has improved significantly during the past decade. However, multi-stage fracturing for multiple closely spaced long horizontal wellbores introduces several technical challenges. One example is Fracture Driven Interaction (FDI). In this study, we document a Fracture Driven Interaction case study where the primary well was drilled into the Three Forks Formation, and an offset well was drilled in the Middle Bakken. The idea of this study was to investigate the possibility of frac-hit as the cause of low production rate in the offset well. This study estimates the stress in the petroleum system, and combine that with petrophysical analysis to construct a fully coupled hydraulic fracturing, geomechanics and reservoir numerical model. The model matched the production data and the results show the occurrence of a fracture driven interaction was a result of stress decrease due to depletion. Fracture driven interaction effect was severe on the offset well reducing the stimulated reservoir volume, thus jeopardizing the production.

1. INTRODUCTION
During the last decade, hydraulic fracturing designs included larger proppant volume injection in order to maximize stimulated reservoir volume (SRV) and increase recovery (Gupta et al., 2021; Seth et al., 2020; Xu et al., 2018). Along with implementing multi-pads, a connection between fractures from adjacent wells was noted. This connection was defined as Fracture Driven Interaction (FDI) so called frac-hit or frac-bashing (Daneshy, 2020). Miller et al. (2016) reported the impact of FDI on production for several plays of the United States. This effect can cause either an increase or a decrease in production. FDI was first reported in the work of Ajani and Kelkar (2012). Gupta et al. (2021) reported the factors that can cause an FDI to occur. In this work, we focus on two factors: stress profile and depletion.
When depleting the primary well (parent well), pore pressure decreases, leading to a decrease in the total stress around the primary well. Consequently, the new distribution of stress will cause asymmetric growth in the fractures of the offset well (child well). The asymmetric growth reduces the stimulated reservoir volume because the fractures grow in the direction of the depleted zones, i.e., the zones with the least resistance to propagation (Ajani & Kelkar, 2012; Daneshy & King, 2019; Gupta et al., 2021; Kumar et al., 2020; Manchanda et al., 2017; Rezaei et al., 2019; Seth et al., 2020; Zheng et al., 2019)
Simulation of Wellbore Annular Closure in Salt Formations Due to Creep: Potential for Natural Sealing Barrier
Authors: Mazon A. L. , Fontoura S. A. B. 
Published: September 2022

ABSTRACT:
Wellbore construction through salt formation remains a great challenge in drilling engineering in many oil provinces around the world due to its unique mechanical properties, in particular, its high creep mobility under downhole conditions. However, once the casing is defined, the behavior of salt is ideal and can provide a necessary and economically beneficial natural barrier. The aim of this paper is to model wellbore closure in salt throughout uncemented casing zones considering both open annular. For this, a computational methodology was developed and evaluated through the reproduction of studies about the formation of natural barriers in salt, reported in the literature, is presented. The comparison between the results obtained demonstrates a time difference for annular closure ranging from a few months to a few years, depending of depth and type of salt. Discussions on specific aspects of creep simulation in salt rocks are also discussed at this stage. From that, we present an analysis to estimate the wellbore closure time under field conditions representative of the Brazilian basins, coupling the adjustments made in the previous stage. As a result, it is observed the potential for the formation of natural barriers in saline layers for permanent plug and abandonment operations.

1. INTRODUCTION NATURAL BARRIERS FOR PERMANENT ABANDONMENT OF WELLS
The operations carried out at the end of the useful life of any kind of well (exploration, production or injection) are called permanent plug and abandonment of the well (PP&A) whose objective is to prevent the flow of fluids from the formation and resist the pressures acting above and below.
According to Khalifeh & Saasen (2020), the PP&A operations of a well can reach up to 25% of offshore well drilling costs. Due to the high costs of these operations and the high number of wells to be permanently plugged and abandoned in Brazil in the coming years, the oil and gas industry has increasingly invested in the development of alternative PP&A techniques.
Modelling Failure Propagation Using the Phase-Field Method with the Assistance of Ultrasonic Wave Velocity Measurement
Authors: Li Xu , Si Guangyao 
Published: September 2022

ABSTRACT:
The phase-field method in damage mechanics is attracting increasing popularity in rock engineering, which bridges the gap between microcracking fracture mechanics and quantified damage mechanics. The quasi-static microcrack propagation can be well captured in FEM via the phase-field damage method. However, the determination and calibration of the length scale parameter (ℓ) in the phase-field method are still unclear since the influence width of microcracks cannot be directly observed. In this research, the phase-field damage method is applied to simulate rock behavior under triaxial tests. The length scale parameter is calibrated via ultrasonic wave velocity measurements. The results show that the phase-field damage can be calibrated via ultrasonic wave velocity measurement, which empowers the application of phase-field damage in engineering applications.

1. INTRODUCTION
The microcracks, joints and faults are always challenging geotechnical issues for underground engineering (X. Li et al., 2022; Si et al., 2020). A novel approach to capture microcracking activities is to use the phase-field damage mechanics (Francfort & Marigo, 1998; You et al., 2021). The phase-field damage mechanics enables to simulate crack propagation and coalescence without introducing complicated remeshing in FEM, plausible problem-specific functions (e.g. in XFEM) or any other thermodynamically unfriendly auxiliary equations or mesh manipulations.
The usage of the phase-field damage model involves two additional parameters, namely the critical fracture energy per unit of area (Gc) and length scale parameter (ℓ). Gc describes the energy consumed to form the unit length of fractures, which is related to fracture toughness (Kc). The fracture toughness can be easily captured by ISRM suggested SBC test. However, the length scale parameter represents the influencing width of microcracks, which is hard to be directly measured. Some previous studies casually selected the minimum size of the mesh as the length scale parameter, which may influence the accuracy of the entire phase-field damage model (Duda et al., 2015). In this paper, we proposed an approach to calibrate parameters in the phase-field damage model via ultrasonic wave velocity measurement. The bridge between traditional damage mechanics and phase-field damage mechanics has been established. The proposed model shows great consistency with laboratory results.