bluuebunny/crossref_metadata_2025 huggingface dataset:
Need and Design of a Field Test to Improve the Knowledge on Strength and Behavior of Massive Hard-Rock Pillars in Deep Mines
Authors: Ladinig T. , Wagner H. , Grynienko M.
Published: September 2023

Pillars have a central role in an active stress management approach, which has been proposed for the extraction of thick tabular and massive hard-rock mineral deposits. A mining method making use of this approach, is the novel raise caving mining method. Initially, the pillars have width-to-height ratios of 5 to 10. In the course of stope extraction, the dimensions of the pillars are altered, namely the height of pillars is increased and the width of pillars may be decreased. Consequently, the pillar strength is reduced and pillar crushing is triggered. A stable crushing process must be ensured. Knowledge on the complete stress-strain behavior of massive hard-rock pillars is paramount for the design of these pillars. However, a review shows that there is insufficient knowledge available. An in-situ pillar test is found to be best suited to improve the knowledge. The need for, objective of and design of such a full-scale in-situ pillar test are discussed. An in-situ pillar test is planned in one of LKAB's underground operations in connection with the development of the raise caving mining method. The layout and sequence of the test and the current progress of design and open points in the design are outlined.

INTRODUCTION

Pillars are used in underground mining for several, different purposes. The tasks for pillars comprise regional support of the overburden strata (panel pillars), local support of the immediate roof strata (crush pillars), the separation of adjacent extraction areas (inter-panel pillars), the control of regional convergence and the associated limit of mining-induced seismicity and abutment stresses (stabilizing pillars) and the protection of critical infrastructure, such as shaft systems (protection pillars). This paper addresses massive hard-rock pillars, which take over a central function in an active stress management strategy in massive deposits or in thick tabular deposits. Due to the shape and dimensions of the deposits and the considered purpose, the pillars are massive and they have a width and height in the range of several tens of meters and a length of up to and more than hundred meters.
3D Geomechanical Model Construction and Application of Deep Shale Gas in the Luzhou Block, Sichuan Basin
Authors: Wang Yuan , Yang Henglin , Fu Li , Chen Gang , Yuan Guangjie , Zhang Heng , Wang Zixin
Published: September 2023

Deep shale gas with a burial depth of 3500–5000m became an important area for shale gas development in China. The characteristics of the rock's mechanics and the in situ stress have a significant impact on the drilling and fracturing effects of horizontal wells. Finite element simulation is used to build an accurate in situ stress model from the data of acoustic logging, diagnostic fracturing injection test, FMI imaging logging, and stress measurement. The results show that Young's modulus and Poisson's ratio in the Luzhou block change vertically with the deposition time. The Longmaxi reservoir has an abnormally high pore pressure gradient which ranges from 16.7 kPa/m to 21.7 kPa/m. The stress regime of the Luzhou block is primarily strike-slip type, with an overburden pressure gradient of 25.5kPa/m, and a minimum horizontal stress gradient range of 18.8 to 24.5kPa/m. According to wellbore breakouts and acoustic emission experiments of cores, the ratio between σhmax and σhmin is 1.165. The horizontal principal stress of the reservoir increases with the increase of Young's modulus and pore pressure. The conclusion is that high-precision geomechanical models can effectively serve to improve the efficiency of drilling operations, improve the production of single wells and benefit development.

INTRODUCTION

As an important unconventional energy source, shale gas has become a global hotspot for resource development. Shale gas deposits are abundant in China and are predominantly concentrated in the southern Sichuan Basin (Zou, et al. 2022; Ma, et al. 2021; Zhao, et al. 2020). Currently, deep shale gas deposits with a burial depth of 3500–5000 m have recently achieved a strategic breakthrough and have become an important area for shale gas development in China. However, deep shale gas development still faces numerous geological and engineering problems, though, as a result of the short exploration period, complex geological conditions, and inadequate engineering technology adaptability (He, et al. 2021).

Shale is a typical "artificial gas reservoir" with nanoscale pore space and Nadasi grade permeability, and has no natural production capacity, therefore, commercial development of shale gas needs the use of horizontal wells drilling and large-scale volume fracturing technologies (Jiang, et al. 2017). The effectiveness of horizontal well drilling and large-scale volume fracturing is significantly influenced by reservoir characteristics and in situ stress conditions. During the drilling stage, high shear stress and pore pressure can lead to wellbore stability problems. Loss of circulation and sticking caused by the unreasonable design of drilling fluid density will negatively impact the drilling cycle (Mehrabian, et al. 2017). At the completion stage, casing deformation is a significant obstacle to shale gas production (Chen, et al. 2016).
An Intelligent Prediction Method of Horizontal Well ROP Based on Di-GRU
Authors: Pan Tao , Song Xianzhi , Wang Zheng , Yin Zhiyong , Ji Yong , Zhu Lin , Pei Zhijun , Ye Shanlin , Liu Muchen , Li Zhen , Zhu Zhaopeng
Published: September 2023

At present, with the continuous development of unconventional oil and gas exploration and development, horizontal wells, as an important means of unconventional oil and gas exploitation, have attracted much attention from drilling teams and oil field companies. However, the cost of horizontal well drilling is relatively high, so more targeted construction should be carried out according to the characteristics of horizontal well drilling. Therefore, rate of penetration (ROP) prediction of horizontal wells is extremely important. The current ROP prediction models of horizontal wells mainly rely on manual experience and some mechanism models, and do not take field data and actual construction conditions into account, so the field application effect is difficult to be ideal. To solve this problem, an intelligent algorithm based ROP prediction model for horizontal Wells is proposed and a novel dual-input neural network structure is designed. Sequential data such as hook load and rotary torque are input into Gated recurrent unit’ (GRU) network, and non-sequential data such as bit type are input into back-propagation neural network(BP), which is called Dual Input GRU(Di-GRU) ROP prediction model. The results show that mean absolute percentage error and R-squared of this model are 11.8% and 0.923 respectively. The prediction model based on Di-GRU proposed in this paper has higher accuracy and better mobility, which is of guiding significance for improving the drilling efficiency of horizontal wells.

INTRODUTION

With the deepening of oilfield exploration and development, the development of deep and complex oil and gas reservoirs has become the focus of stabilizing oil and increasing production, which has important strategic significance. At present, horizontal wells have become the main well type for developing complex oil and gas reservoirs(Yassie et al.,2020). Compared with vertical wells, horizontal wells usually have more complex geological conditions and greater drill string friction, resulting in poor formation drill ability and difficulty in drilling the drill string. The low rate of penetration(ROP) and the small footage of a single bit bring severe challenges to drilling engineering and seriously affect the progress of exploration and development(Soares et al.,2019). Accurate ROP prediction of horizontal wells can assist the scientific allocation of resources before drilling and the accurate formulation of operation plans, which is of great significance for improving drilling efficiency and reducing costs. Horizontal well drilling engineering operation is a complex process. Formation, tools and operating parameters all play an important role in the rock breaking of the drill bit, such as formation drill ability, drill bit wear, rotary speed, mud performance, drill bit pressure, build-up rate, etc. Therefore, it is difficult toaccurately predict the ROP of horizontal wells.
Numerical Simulation, Parametric Analysis, and Equipment Design for Backfilling of Waste Rock Cavities with Oil-Based Rock Cuttings
Authors: Luo Yuyang , Hu Naikun , Wei Yaoran , Yang Heng , Deng Jingen , Feng Yongcun
Published: September 2023

Oil-based rock cuttings present a significant technical challenge in terms of the economic, environmental, and efficient processing in the engineering field. This paper employs fluid finite element theory, particle discrete element theory, and particle multiphase flow calculation model to couple the particle domain and fluid domain bi-directionally through the udf compilation interface. By employing the particle segmentation volume fraction model and CFD-DEM multiphase flow equation with particles, the study simulates the process of filling salt caverns with oil-based rock cuttings mixed mud, and analyzes the impact of multi-factors on the overall back-filling effect of the cavities. The results demonstrate that under the conditions of particle size of 4 mm, initial velocity of 5 m/s, and fluid viscosity of 40 m·Pas, the overall trajectory of particle movement aligns with actual working conditions and conforms to the fluid phase velocity distribution. In practical engineering, besides the control of the parameters of parcels, real-time monitoring and adjustment should also be attached according to specific conditions and requirements. Additionally, a sufficient understanding and study of the physical properties of the filling particles and the fluid's properties are required to optimize the parameters and back-filling schemes, ultimately leading to improved backfilling efficiency.

INTRODUCTION

Due to the characteristic of salt minerals being soluble in water, the exploitation of salt deposits commonly uses the method of water-soluble mining (Liang et al., 2004). If the salt mine is stopped exploitation or abandoned, a large amount of abandoned salt cavities will be generated underground. If the cavity is not backfilled and sealed in time, the continued dissolution of cavities will lead to further problems such as roof collapse, forming severe geological disasters.

Salt cavities have the characteristics of deep burial, good sealing, and high safety. It is suggested to consider using salt cavities to treat nuclear waste and establish salt cavity gas storage facilities (Ding et al., 2015). It is also recommended to strengthen the research on automation control systems, reduce the convergence of dissolved cavities, and enhance stability assessment standards (Xiao, 2012).
Fracture Propagation Behaviors of High-Temperature Granites During Liquid Nitrogen Fracturing with Multi-Branch Wells
Authors: Sun Yaoyao , Wu Xiaoguang , Zou Wenchao , Huang Zhongwei , Xie Zixiao , Li Jingbin , Long Tengda
Published: September 2023

We propose a low temperature medium fracturing mode in combination with a multi-branch well to overcome the challenges of difficult initiation, communication, and control in the traditional hot dry rock (HDR) fracturing. Fracturing experiments on multi-branch wells subjected to various fluid conditions were conducted to analyze and compare fracture behavior. The method of pressure curve fitting analysis and the method of permeability test by re-injection fracturing fluid were used to quantitatively characterize the rock fracture morphology and evaluate the effect of liquid nitrogen (LN2) fracturing. The characteristic of injection pressure of HDR with different numbers of branch wells under LN2 fracturing are compared, and the characteristics of fracture morphology of HDR are evaluated. The experimental results show that: ① compared with hydraulic fracturing, multi-branch well can reduce the breakdown pressure in a certain range (About 25 to 61 %), and breakdown pressure can be further decreased under LN2 stimulation; ② with the increase of the number of branched boreholes, the extension of fractures is longer and fracture interconnection is better; ③ The HDR after multi-branch well fracturing has better conductivity than that of hydraulic fracturing. According to the experimental results, the multi-branch wells can enhance the thermal shock areas of LN2 in HDR, and has a great potential in creating complex fracture network. This technique is expected to provide a new insight into better developing HDR geothermal.

INTRODUCTION

Geothermal energy is an important part of the world's energy plan for the 21 centuries. It has many benefits over traditional energy sources, including being clean, efficient, and having large reserves (Lu et al,2018). The type of geothermal energy we’re talking about is found deep underground in certain rocks, like granite and gneiss. There are many ways to get this energy out of the ground, but the most common one is called an enhanced geothermal system. This involves creating fractures in the rock using a special fluid, so that hot water can be pumped through the rock and used to make electricity. Scientists are working to find ways to make this process more effective and cheaper.
Evaluating the Geothermal Potential of Hot Sedimentary Aquifers Using a Hybrid Approach
Authors: Cottrell Mark , Lacazette Alfred , Chmela Bill , Karimi Saman , Marsh B. D.
Published: September 2023

Flow through geothermal reservoirs is highly complex, and often includes contributions from both fracture networks and the porous rock matrix. Discrete Fracture Network (DFN) models are proven, effective tools for the characterization of rock masses especially where fracture dominated fluid flow is encountered; whereas more conventional tools, such as Finite Volume (FV) methods, are more numerically favorable for simulating problems where detailed multiphysics is required.

This paper presents a workflow that combines discrete and continuum descriptions that captures the salient features of the geological materials whilst also remaining numerically tractable. DFN models of fractured rock masses are typically developed using statistical distributions to generate realistic three-dimensional (3D) descriptions of the natural fracture network. Superimposed with this fracture description, is a matrix-orientated description based on an intact rock property model. Integration of these two descriptions into a single continuum rock mass description is achieved through a novel discrete-continuum upscaling process which combines fractures and intact properties into a unified form, providing effective mass permeability and geomechanical descriptions.

The composite rock mass description is then carried forward into a numerically efficient multiphysics solver that provides effective simulation of both temperature and flow in a fully coupled manner to evaluate the performance potential of geothermal reservoir units. In addition, it will be demonstrated how the presented work can naturally embed within the stochastic framework of DFN and permit a probabilistic based evaluation.

This paper presents application of the hybrid DFN-FV workflow for a hot sedimentary aquifer. The application is presented in terms of the characterization steps and a description of the input used, which is then supplemented with the dual fracture and matrix description. The demonstration will also touch on the efficient gridding of geological domains and provide example simulation results of multi-well injector and producer fluid flow and heat transfer. The work in this paper shows how the DFN-FV approach can be systematically employed to help with the success of geothermal well placement and completion studies in hot sedimentary aquifers.
An Analytical Solution for Linear Elastic Geomechanical Responses in a Layered Vertical Transversely Isotropic Medium
Authors: Yan H. , Park J. , Holt R. M. , Bakk A.
Published: September 2023

The isotropic homogenous assumption in the conventional Geertsma model is often contradicted by reality because the rock properties in the overburden are typically anisotropic and often can be quite different from the reservoir. Thus, we present an analytical solution that extends Geertsma's solution and can consider layered subsurface, including anisotropic elasticity. Namely, five independent parameters are assigned in each anisotropic layer in this analytical model. The derived functions are expressed in terms of both displacements and stress fields accounting for any number of layers. Different from the original Geertsma model, this model also describes horizontal stress changes inside the reservoir. We assess the analytical solution's performance, advantages, but also limitations by comparing it to finite-element numerical modelling results in three cases. The results of the analytical solution agree well with those of the numerical solution for both fully anisotropic and isotropic cases. It is also learned that side-burden has a minor impact on stress and displacements for the case with anisotropic surrounding around a depleted isotropic reservoir. The analytical solution enables us to achieve sufficiently accurate results with low computational cost and be focused on the essential features of the Geertsma-type geomechanical problems.

INTRODUCTION

Pore pressure changes due to fluid injection for underground carbon storage or depletion for hydrocarbon production can cause stress redistribution in the subsurface. Therefore, a quantitative understanding of the geomechanical changes in the subsurface is essential for safe drilling and carbon storage processes. ‘Stress path’ is commonly used to help understand the changes in the stress state within the rocks around or inside an injected or depleted reservoir. For the overburden, the stress path coefficient κov is defined as the ratio between total horizontal stress change ΔSr and total vertical stress change ΔSz for an axisymmetric model:

(Equation)

The value of κov corresponds to different stress change scenarios. For example, three values of κov −0.5, 0, and 1 correspond to constant mean stress (CMS) change, uniaxial stress change, and isotropic stress change, respectively. Studying the stress path is crucial for safe reservoir operation and can help design monitoring strategies to prevent geomechanical instability and other risks.
Research on Productivity Recovery Mechanism of Fractured Parent Well of Interwell Stereodimensional Infill Well in Fuling Shale Gas Reservoir, Sichuan Basin
Authors: He Yongsheng , Tang Xuanhe , Zhu Haiyan , Li Kuidong , Liu Wei , Zheng Feng , Xiao Jialin , You Yuan
Published: September 2023

During the fracturing process of infill wells in the Fuling shale gas reservoir, it was found through real-time monitoring of fracturing that the monitored pressure of the parent well increased to different degrees when each fractured stage of the adjacent infill wells was fractured, and a significant increase in production following the re-opening of the well. To study the production and pressure recovery mechanisms of parent well associated with the infill well fracturing, a coupled flow and geomechanics model was established based on the comprehensive work flow of four-dimensional in-situ stress during the devolopement of multi-layer three-dimensional infill horizontal well in shale gas reservoir.

In the integrated modeling, a natural fractures network was embedded in the geological model firstly. Second, a fracturing model is developed to simulate hydraulic fracture propagation of parent wells. Thirdly, a coupling flow and geomechanics model was established to simulate the spatiotemporal stress evolution in a multilayer shale gas reservoir with complex fracture geometry. Finally, the complex hydraulic fractures propagation of the infill well was stimulated. It can be concluded from the simulation results that: (1) Reservoir stress changes are influenced by fracture modification, but the range of stress evolution is greater than the range of fracture modification; (2) The natural fracture zone connects the fractured wells to the producing wells, and the fluid can be run long distances through the natural fracture zone to the fracture modification edge of the old wells to achieve the fracturing of more wells and to increase the production of the old wells (3) The fractures(tennsile fractures, shear fractures) communicating between the fractured edges of the tightened wells and the old wells are able to transfer fracturing fluids and add production to the old wells.

This discovery is beneficial to the production of fractured encrypted wells and the continued high production of old wells.
Prediction of Diverting Performance of VES Acid Based on SVM and Coupled Rheology-Reaction Model
Authors: Wang Yunjin , Zhou Fujian , Zhang Ying , Zhang Guchang , Wang Qing , Shi Guanghao , Jiang Tingxue , Dong Rencheng
Published: September 2023

Viscoelastic-surfactant (VES) acid is widely used in heterogeneous carbonate reservoir as an important acid system for uniform acidizing. Temperature is a significant parameter that affects the rheological properties and reaction rate of VES acid. However, existing rheological models of VES acids do not consider the effect of temperature, and the diverting performance of VES acid at different reservoir conditions and injection technology is still unclear. Here, the relationship between the rheology of spent VES acid and temperature was studied, and the rheological model of VES acid was optimized. A coupled model of temperature field and two-scale continuum acidizing model was established. Based on this model, the effects of temperature, injection velocity and permeability contrast on the diverting performance were investigated. In addition, a support vector machine (SVM) model was introduced to train and predict the diverting results. The results showed that the viscosity of spent VES acid increased and then decreased with the increase of temperature. With the temperature increasing to 313 K, the viscosity of spent acid reached the maximum of 453.1 mPa·s. The higher the temperature, the worse the diverting performance of VES acid. When the temperature was higher than 343 K, the distance of wormhole propagation was significantly reduced. When the temperature is high, the diverting performance of VES acid can be improved by appropriately increasing the injection velocity. However, when the injection velocity is higher than 0.005 m/s, the uniform dissolution due to the excessive injection velocity will reduce the acidizing efficiency. The higher the permeability contrast, the worse the diverting performance. The maximum diverting permeability contrast of VES is not a constant. The maximum diverting permeability contrast of VES acid at a temperature of 323 K and 343 K is about 10 and 8, respectively. The SVM model has high accuracy for diverting performance prediction of diverting acid, with an overall average correct prediction rate of 87.5% for 200 repetitions of training and prediction. This work quantifies the effects of temperature, injection velocity, and permeability contrast on diverting performance, and proposes a diverting performance prediction model for diverting acid system.
Modeling and Analysis of Micro Proppant Transport and Deposition in Rough Fracture Networks
Authors: Zhou Qianqian , Wang Haizhu , Wang Bin , Zheng Yong , Stanchits Sergei , Cheremisin Alexey
Published: September 2023

Micro-proppants are instrumental in maintaining secondary fractures, which evolve around primary propped fractures in unconventional formations. Given their minute size, micro-proppants can infiltrate induced fractures, thereby augmenting production through the fracture network. Yet, the mechanisms through which micro-proppants bolster the conductivity of secondary fractures remain incompletely elucidated. To bridge this knowledge gap, we have conducted a simulation study that models the transport and sedimentation of micro-proppants in rough fractures. We utilized a coupled computational fluid dynamics and discrete element method (CFD-DEM) for this purpose. Our research also considers key determinants such as particle properties, fracture morphology, and injection parameters to assess their impact on the flow field and micro-proppant distribution. Preliminary findings indicate that, unlike larger proppants, micro-proppants are not impeded by rough and tortuous fracture surfaces, enabling a more uniform proppant distribution due to their smaller particle size. These insights deepen our comprehension of particle settling behavior in rough rock fractures and underscore the benefits of using micro-proppants. They will also assist in the design of more effective fracture enhancement projects.

INTRODUCTION

Hydraulic fracturing serves as a pivotal method for enhancing oil and gas recovery from wells. This is accomplished by the high-pressure injection of a mixture comprising water, sand, and chemicals into rock formations. This process induces fractures in the rock, thereby releasing entrapped hydrocarbons. Despite its experimental beginnings in 1947 in the Hugoton gas field of Grant County, Kansas, in the United States, the first successful commercial application was not realized until 1950. Numerous oil and gas fields would be economically nonviable without the implementation of hydraulic fracturing. Proppants, solid particles instrumental in maintaining the created fracture pathways and preventing fracture closure post-fluid injection, are an integral part of the fracturing process. The placement and properties of the proppant bed within the stimulated fracture network are crucial determinants of the efficacy of the fracture network and the eventual productivity of the well (Kong et al., 2015; Montgomery et al., 2010). Recent decades have witnessed improved understanding of proppant transport mechanisms in hydraulic fracturing, thanks to numerical simulation. This has led to the optimization of proppant types, fracturing fluid compositions, and injection strategies.
The Effect of SCCO2 Treatments on the Petrophysical Properties of Continental Shale with Different Mineral Compositions
Authors: Sun Lianhe , Wang Haizhu , Wang Bin , Dang Kaiyan , Shi Mingliang , Zhang Yunpeng , Liu Mingsheng , Wu Yuqian
Published: September 2023

CO2 Pre-pad Energized Fracturing has been widely used in China in recent years to effectively develop shale oil. The petrophysical properties of continental shale vary with different sedimentary conditions. However, it is unknown how CO2 pre-injection affects these properties for different continental shale reservoirs. In this study, three sets of continental shale from the Qikou Sag, Jiyang Depression, and Yanchang Formation were selected for the experiment. The effects of SCCO2 on the petrophysical properties of different samples were analyzed by N2GA, XRD, and uniaxial compression tests. According to the results, the SCCO2-water-shale interaction induced the dissolution and precipitation of shale minerals during the immersion test. In addition, the average pore size of QK samples increased due to the dissolution of minerals, while the strong swelling effect and mineral precipitation reduced the average pore size of JY and YC samples. After interacting with SCCO2, the pore structure complexity of the QK and JY samples decreased slightly. Furthermore, the changes in mineral matrix and pore structure led to significant deterioration of the mechanical properties of the three shale groups, especially for the JY sample. These findings provide an experimental basis for applying CO2 Pre-pad Energized Fracturing technology to different continental shale reservoirs.

INTRODUCTION

In recent years, with the advancement of oil and gas exploration and development technology, China has made major breakthroughs in unconventional oil and gas development, and the proven reserves of unconventional oil and gas account for 41% of the country's oil and gas resources (Yang et al., 2015). As an important unconventional oil and gas resource, shale oil is mainly divided into two types: continental and marine. Continental shale is the main shale oil reservoir in China, and its development and utilization are different from those of marine shale oil in North America in terms of geological environment and development methods (Wenzhi et al., 2020). At present, shale oil enrichment layers have been discovered in numerous basins in China, such as the Junggar Basin, the Ordos Basin, and the Bohai Bay Basin (Feng et al., 2020; Ju et al., 2020). In 2022, Wu Xiaozhi (Xiaozhi et al., 2022) predicted that the national shale oil geological resources would reach 335.3 × 108 t. Therefore, realizing the efficient and economical development of continental shale oil is of great significance for ensuring China's energy security.
Prediction of Fault Damage Zones Using Artificial Neural Networks
Authors: Santos L. F. , Quevedo R. , Carvalho B. R. B. M. , Roehl D. M.
Published: September 2023

Fault damage zones can affect the flow pattern in reservoirs owing to the presence of geological structures such as fractures and deformation bands. Therefore, preliminar and fast characterization of damage zones is vital for developing exploration and production strategies. This study proposes a methodology for assessing the damage zones widths using artificial neural networks (ANNs). The database used to train the ANNs was built considering several numerical models which adopt geomechanical parameters, fault length, and maximum displacements as input variables to determine the damage zone along a single fault. Such numerical models are based on elastoplastic constitutive relationships and the finite element method (FEM). The best set of hyperparameters for the neural network model is defined through a Bayesian optimization strategy, which found a simple neural network with one hidden layer, 76 neurons, and a learning rate of 0.024. The rectified linear unit (ReLU) and the adaptative stochastic gradient descent method (ADAM) are adopted as activation function and optimizer algorithm, respectively. The damage zone width along the fault was predicted and compared with the expected responses of the numerical FEM models, reaching a coefficient of correlation of R2 = 0.989, a mean absolute error equal to 2,428 meters, and a mean absolute percentual error of 4,2%.

INTRODUCTION

The study of geological faults present in reservoirs is essential in the petroleum engineering and geology field. In general, these faults can directly affect the exploration and production of oil and gas reservoirs, acting as pathways for fluid migration or barriers (Holder, 1993; Davies & Swarbrick, 1997).

Faults can promote zones of high permeability due to fractures allowing preferential flow paths in some regions of the reservoir. On the other hand, faults can also act as barriers owing to decreases in porosity and permeability provoked by crushing and compaction of the host rock (Caine et al., 1996; Paul et al., 2007; Hennings et al., 2012; Zhao & Zhang, 2020; Qiao et al., 2019; Hu et al., 2019; Meng et al., 2019; Sun & Wu, 2019).
Heavyweight Magnetite as a Novel Weighting Material for Cementing HPHT Formations
Authors: Alvayed Dandi , Mahmoud Ahmed Abdulhamid , Elkatatny Salaheldin , Alafnan Saad
Published: September 2023

The development of cement slurry with specified qualities, such as high density, is necessary to overbalance the high-pressure formations while cementing deep and ultra-deep oil wells. Hematite is now primarily utilized as a weighing material in oil fields, although its use raises several operational and environmental issues. The creation of a non-elastic cement matrix and cement segregation are the two most frequent problems associated with using hematite as a weighing ingredient. This study examined the effectiveness of using magnetite as a weighing component when cementing a deep production casing at a depth of 15,000 feet. The magnetite used in this study has a particle size of 18.84 μm and is composed of more than 99% iron. In-depth laboratory research was done on the performance of 18.0 ppg hematite- and magnetite-weighted cement slurry. In this work, the qualities of cement segregation, compressive and tensile strength, porosity and permeability, and elastic properties were investigated. This study demonstrated that using magnetite instead of hematite as a cement-weighting material might be successful. The density of the created magnetite-based cement system varies very slightly along the depth of the well, with only a 7.3% difference between the top and bottom of the cement. Both the casing and the drilled formations may be supported by the magnetite-based cement's high compressive and tensile strengths of 65.1 and 8.1 MPa, respectively. Additionally, impenetrable, the cement system created with magnetite has a permeability of only 0.003 mD. The capacity of the Magnetite-based system to lower the Poisson's ratio and boost cement elasticity, which is highly essential, especially for very deep wells, was confirmed when Poisson's ratio for the system created in this work was compared with that of hematite-based.

INTRODUCTION

Weighting materials are used to increase the drilling fluid's density to successfully balance the higher pressures in deep wells (Caenn et al., 2011; Hossain & Al-Majed, 2015; Stroud BK, 1922, 1926). When dealing with unbalanced wellbores, deformable/plastic formations, and high pore pressures, high mud weight above 18 ppg can be utilized, and cement samples of equivalent weight should be used (Magarini et al., 1999). The well may never produce its most total capacity without effectively isolating problematic zones (Nelson, 1990). Primary oil-well cementing procedures are carried out to meet various goals, including inhibiting fluid communication and flow between drilled formations and the wellbore, shielding the casing from acidic liquid attack, and supporting the casing (Mitchell & Miska, 2011).
On the Path to Least Principal Stress Prediction: Quantifying the Impact of Borehole Logs on the Prediction Model
Authors: Dvory N. Z. , Smith P. J. , McCormack K. L. , Esser R. , McPherson B. J.
Published: September 2023

Knowledge of the minimum horizontal principal stress (Shmin) is essential for geo-energy utilization. Shmin direct measurements are costly, involve high-risk operations, and provide only discrete values of the required quantity. Other methods were developed to interpret a continuous stress sequence from sonic logs. These methods usually require some ‘horizontal tectonic stress’ correction for calibration and rarely match sections characterized by stress profiling due to viscoelastic stress relaxation. Recently, several studies have tried to predict the stress profile by an empirical correlation corresponding to an average strain rate through geologic time or by using machine learning technologies. Here, we used the Bayesian Physics-Based Machine Learning framework to identify the relationships among the viscoelastic parameter distributions and to quantify statistical uncertainty. More specifically, we used well logs data and ISIP measurements to quantify the uncertainty of the viscoelastic-dependent stress profile model. Our results show that the linear regression approach suffers from higher uncertainty, and the Gaussian process regression Shmin prediction shows a relatively smaller uncertainty distribution. Extracting the lithology logs from the prediction model improves each method's uncertainty distribution. We show that the density and the porosity logs have a superior correlation to the viscoplastic stress relaxation behavior.

INTRODUCTION

Comprehensive recognition of the least principal stress is essential for economic multistage hydraulic fracturing stimulation design. It is well established that hydraulic fractures propagate perpendicular to the least principal stress and that the stress profile prominent the hydraulic fractures generation in both the lateral and horizontal direction (Fisher et al., 2012; Hubbert and Willis, 1957; Kohli et al., 2022; Valkó and Economides, 1995; Zoback et al., 2022)c. In other words, the stress layering could act as a ‘frac barrier’ that limits fracture development in discrete directions and promotes progress in different directions (Singh et al., 2019). Detailed knowledge of the least principal stress profile is significant for hydraulic fracture growth assessment, proppants technology optimization, and efficient landing zone detection (Pudugramam et al., 2022). Traditionally, these considerations were aligned with the oil and gas industry. Still, today, they have substantial implications for enhanced geothermal system development, carbon storage integrity, and in a broader sense, a safe path for a carbon neutrality economy.
3D Hydraulic Fracture Propagation in a Heterogeneous Rock Formation Using a Mesh Transition Technique
Authors: Rueda C. J. , Mejía C. , Paullo L. F. , Roehl D. , Rossi D. , Henriques F.
Published: September 2023

Hydraulic fracturing is a stimulation technique widely used in oil and gas production. Forecasting the induced fracture geometry can improve the efficiency of the stimulation process. Traditional numerical models consider fracture propagation in homogeneous formations. However, in carbonate reservoirs, the high variation of the rock formation properties due to anisotropy and heterogeneity can affect hydraulic fracture propagation. This work presents a numerical methodology to simulate 3D fluid-driven fracture propagation in a carbonate reservoir. The heterogeneity is introduced as a multi-layered formation. The model incorporates fractures using interface elements with the pore-cohesive zone model (PCZM). A mesh transition technique is adopted using the tie constraint technique to reduce the computational cost and maintain the solution's accuracy. The model is verified against analytical solutions. Moreover, the work investigates the influence of the mesh transition on the numerical results and the computing time. The numerical results show that many slave elements per master element can reduce the accuracy and computational efficiency. Finally, we study the main parameters that affect fracture propagation in a large-scale heterogeneous formation.

INTRODUCTION

Hydraulic fracturing is one of the most commonly used stimulation techniques to enhance reservoir permeability in oil and gas production. The correct prediction of the hydraulic fracture geometry results in the stimulation process's efficiency (Barbier, 2002; O’Sullivan et al., 2001). Several approaches have been developed to model the hydraulic fracturing process, such as analytical solutions (Adachi & Detournay, 2002, 2008; Bunger et al., 2005; Detournay, 2016; Dontsov, 2016, 2017; Garagash et al., 2011; Savitski & Detournay, 2002), pseudo-3D models (Nasirisavadkouhi, 2015), and numerical solutions. The analytical solutions assume a linear elastic behavior for the rock formation and disregard the energy dissipation or plastic deformation at the fracture tip. Numerical solutions are more suitable for modeling hydraulic fracturing, especially considering nonlinear material effects, rock formation heterogeneity, complex boundary conditions, and hydromechanical coupling terms. In the last decades, several numerical formulations have developed to simulate hydraulic fracturing: finite elements (Rueda Cordero et al., 2019), displacement discontinuity method (J. Xie et al., 2018; L. Xie et al., 2016), discrete element method (Fatahi et al., 2017; Zhou et al., 2017), and mesh-free discretization (Keshavarzi & Jahanbakhshi, 2013; Khoei et al., 2016; Taleghani, 2010; Wang et al., 2018).
Ground Support Asset Management
Authors: Wellman E. C. , Akbulut N. A. , Kemeny J.
Published: September 2023

Geotechnical Asset Management is an approach that has been adopted by civil infrastructure and state highway departments to assess the "value" of rock slopes and develop a tool to assess the cost-effectiveness and importance of prioritizing slope and ground improvement projects to enhance transportation corridor reliability. The Ground Support Asset Management program aims to adopt an asset management framework for the underground construction and mining sectors.

The University of Arizona operates the San Xavier Mining Laboratory south of Tucson, Arizona. The mine has adits and openings over three levels, including shaft access. The S.X. underground mine will be the launch site and be used as a testbed for trialing the Ground Support Asset Management program. Key aspects that degrade the useful life of elements are corrosion and deformation due to excessive convergence yielding ground in weak rock, deep, and high-stress environments. The primary focus will be on utilizing systems that collect high-resolution point clouds and spectral data to assess deformation and corrosion based on the point cloud data. A secondary project aim is to assess the rock mass and ground conditions for rock reinforcement and ground support design.

The research project aims to develop a framework to assess the remaining useful life of ground support and rock reinforcement elements. Then, using the tools and logic developed in this project, the U.A. San Xavier mine and other mining companies can make informed decisions on when to rehabilitate access drifts and critical openings based on proper safety and economic basis.

INTRODUCTION

Fall of Ground (FOG) events still occur in underground mines – even in areas of supported ground. These events are typically the result of unsupported or inadequately supported ground. Like slope failures, FOG occurs with precursory deformation that can be confirmed with monitoring. Convergence is currently measured in underground mines using tape extensometers, multipoint borehole extensometers, or fixed-station lidar systems. These are now commonly used in underground mines in high occupancy and high-traffic areas. Lidar scanners are commonly used for mine surveys; however, repeated scans are not usually undertaken to measure convergence and geomechanical monitoring. This is due to the time it takes to conduct a scan and the additional processing time to calculate deformation or convergence from successive scans.
Study on the Optimization of the Integrated Process Parameters of Fracturing and Flooding in Beach Bar Sand Reservoir
Authors: Ma L. , Lu C. , Guo J. C. , Wang Y. C. , Jiang Z. X. , Chen B. G. , Zhou Y. L. , Yuan H. R. , Tang Z. B. , Sun P. X. , Wen X. L. , Qi D. , Huang W. H. , Ding H. X. , Diao D. X. , Wang M. , Xu J. B.
Published: September 2023

The beach bar sand reservoir has the characteristics of low porosity and permeability, multiple thin layers and strong vertical heterogeneity. In recent years, the integrated technology of fracturing and flooding has been put forward. Based on the geological model of injection-production well group, optimization of water injection parameters of fracturing-flooding and the optimization of production well fracture parameters under the condition of fracturing and flooding are carried out in the stimulation of beach bar sand reservoirs. The research results show that optimizing the water injection volume of fracturing-flooding based on numerical simulation is 50000∼100000 m3, and the water injection rate of fracturing-flooding is 0.7∼0.9 m3/min, which can reduce the risk of production well water channeling and achieve the goal of balanced water injection. Then, the front edge of water injection in fracturing-flooding is determined by analyzing the sweep area of fracturing water injection. Based on the well spacing and ultimate flow distance of low permeability reservoirs, the half length of fractures in different types of production wells was optimized. The research results can effectively guide the economic and efficient development of beach bar sand reservoirs under the condition of fracturing-flooding and water injection.

INTRODUCTION

Bin435 block of Shengli Oilfield is located in Binzhou City, Shandong Province. It is structurally located in the west slope of Lijin depression. Oil layers are drilled in the upper S4 sub-member of Shahejie Formation. The area of the work area is 1.23 km2 and the crude oil reserves are 208 × 104 t. The upper sub-member of the target layer of Shahejie Formation consists of 1∼4 sand formations, with a buried depth of about 2700∼2900 m. It is a beach bar sand deposit with sand and mud interbedding. The sandstone is mostly gray or light gray siltstone, argillaceous siltstone and calcareous siltstone. The mudstone is gray or sandy and mainly gray. The overall structural feature is a monoclinic structure complicated by the fault layer. The average porosity of the reservoir in this block is 14.6%, and the average permeability is 6.2 × 10−3 D. There are many small oil-bearing layers with a longitudinal span of 150 m, the average thickness of the sand body is small, the single-layer protrusion coefficient is large, and the vertical and horizontal heterogeneity is strong. It belongs to the typical low porosity and low permeability beach bar sand reservoir (Shao, 2012).
Digitalization in Mining Geomechanics – Looking to the Future
Authors: Mitra R.
Published: September 2023

According to Deloitte (2014), the term "Industry 4.0" refers to the next development stage in the organization of the entire value chain process in the manufacturing industry. The mining industry, just as any other industry, is also in the process of moving into this new stage. The challenges facing the mining industry are increasing, with environmental concerns becoming broadly understood, emergent technology changing the nature of work and society and resource nationalism fueling the expectations of a better life. New and emergent technology and working practices, increased stakeholder expectations around competitive economic returns and rents, and community expectations for an inclusive and sociably acceptable industry is leading to changes in the roles and attributes of the mining engineer of the future (Smith 2017). Similar to other areas within the mining industry, there is a lot of digitalization being implemented in the field of mining geomechanics. This paper will review some of those technologies that have been developed in the field of mining geomechanics along with looking into some future opportunities.

INTRODUCTION

According to Deloitte (2014), "Industry 4.0" refers to the next development stage in the organization of the entire value chain process in the manufacturing industry. The first industrial revolution was observed in the late 18th century with the arrival of steam power and the invention of the power loom. This led to mechanization and radically changed how goods were manufactured. The late 19th century saw the second industrial revolution when electricity and assembly lines made mass production possible. In the beginning of the 1970s, the third industrial revolution was observed. During this time, advances in computing enabled the programming of machines and networks, powering automation (Deloitte 2018). An overview of the evolution of these industrial revolutions can be seen in Figure 1.

According to Marr (2016), Industry 4.0 introduces what has been called the "smart factory". In this system, the cyber-physical systems monitor the physical processes in the factory and make decentralized decisions. The physical systems become an Internet of Things (IoT), communicating and cooperating both with each other and with humans in real time via the wireless web. The development of Industry 4.0 will be accompanied by changing tasks and demands for the people in the factory (Gorecky et al., 2014).