bluuebunny/crossref_metadata_2025_split huggingface dataset:
Sand Production Prediction of Depleted-Reservoir Underground Gas Storage – An Experimental Study
Authors: Ma Lijun , Dong Jingnan , Wang Jinzhong , Zhang Yuda , Li Guotao , Li Jingcui 
Published: September 2022

ABSTRACT:
Depleted-reservoirs underground gas storage are playing an increasingly important role in seasonal demanding of natural gas, ensuring stable gas supply and strategic reserves. However, due to the physical properties of the reservoir, the problem of sand production in the wellbore cannot be ignored. This research is based on the high-pressure sand production experiment simulation device system. Using the in-situ core, through experiments to simulate the sand production of the high-pressure gas storage reservoir, the sand production is systematically and quantitatively studied. The experimental results show that there are two key pressures for sand production caused by the destruction of the inner wall of the wellbore, namely, the equivalent initial sand production pressure (critical confining pressure) and the strength of the thick-walled barrel (collapse pressure). After the confining pressure exceeds the equivalent initial sand production pressure, the core begins to produce sand, and the sand has a relatively smaller particle size. The sand production is found to increases linearly with the equivalent confining pressure. After the confining pressure exceeds the strength of the thick-walled barrel, the core body is damaged and a large amount of sand is produced. The sand body has a relatively large particle size. The particle size distribution indicates the increase of sand particle size during the sand production of the gas storage well. This experiment provides guidance for the operation and completion of gas storage in depleted oil reservoirs, and also provides a quantitatively experimental method for the study of wellbore sand production.

1. INTRODUCTION
In recent years, with the increasing demand for natural gas, the stable supply of natural gas has attracted more and more attention. Therefore, gas storage as a means of peak regulation has developed rapidly in a short period of time in China. As a safe, efficient and convenient gas storage place, the stable operation of gas storage needs a higher technical level as a support (Wei et al., 2015;Dong et al., 2020). Compared with regular gas production wells, there are two main reasons why gas storage wells are more prone to sand production:
• The service life of gas storage wellbore is longer than that of production wells, generally about 30 to 50 years. The long-term stress alternation will weaken the cementation and connection between rock particles, resulting in instability of wellbore wall and the damage of the formation.
• When the supply and demand are unbalanced due to seasonal changes, the gas storage needs to meet the operating conditions of high throughput and large discharge. Under the action of the highspeed fluid dragging force, the wellbore has a higher probability of sand production. (Wei et al., 2019; Li et al., 2005; Liu et al., 2021)
Experimental Study on Fracture Propagation Morphology of Deviated Well in Tight Reservoir
Authors: Cui Zhuang , Hou Bing , Zeng Yue , Jiang Kaining , Zhuang Li , Elsworth Derek 
Published: September 2022

ABSTRACT:
The highly efficient production method of tight reservoir in complex fault block reservoir is large slope cluster well volume fracturing. The characteristics of fracture initiation and propagation in deviated Wells of tight reservoirs under different stress states and well trajectory parameters have not been clarified yet. Based on the laboratory physical simulation test of true triaxial hydraulic fracturing, this paper studies the law of fracture propagation caused by various factors such as horizontal stress difference, well inclination Angle and azimuth Angle. The experimental results show that under low horizontal stress difference coefficient, spiral perforation is beneficial to the initiation of multi-hole fracture, but the fracture near the wellbore is seriously distorted. Directional perforation under high horizontal stress difference coefficient is favorable for hole initiation, forming complex fractures dominated by single smooth fractures and supplemented by secondary fractures. 20° or 80° well oblique fracture is smooth fracture, fracture surface distortion degree is small, perforation orifice initiation point is less; When the inclination Angle is 40° and 60°, the perforating hole has more fracture initiation points, high fracture extension pressure and high fracture plane distortion. When the azimuth Angle is less than 80°, it is beneficial to add sand on site.

1. INTRODUCTION
China’s unconventional oil and gas reserves are rank among the top in the world, unconventional oil and gas are mainly tight oil and gas (Zhen et al., 2019; Sun et al., 2019). Due to its low porosity and low permeability characteristics, tight reservoirs are mainly stimulated by horizontal well volume fracturing (Zhu et al., 2019; Hou et al., 2021). However, the tight sand-mudstone reservoirs in complex fault-block reservoirs have many vertical layers, and the scale of the plane sand bodies varies greatly. The most effective mining method for vertical multi-layer tight sand-mudstone reservoirs is volume fracturing with high-angle cluster wells. The mechanism of hydraulic fracture initiation and propagation of perforated fracturing in highly deviated wells is unknown, and it is difficult to add sand during on-site construction, resulting in high construction pressure and small reservoir stimulation volume. Therefore, it is of great significance to study the fracture propagation pattern and construction influencing factors of perforated hydraulic fracturing in highly deviated wells for reservoir stimulation.
Investigation on Diversion Acidizing for Fractured Carbonate Reservoir: An Case Study from KOA Oilfield in Kazakhstan
Authors: He Jiayuan , Li Xiaolong , Li Feng , Mou Jianye , Wang Haibo , Zhang Lufeng 
Published: September 2022

ABSTRACT:
Fractured carbonate reservoir with thick formation and heterogeneous intervals, widely distributed in Kazakhstan, are the significant gas exploration and exploitation area and have a profitable development prospect. For such reservoirs, diversion acidizing is an indispensable technology to unlock the production potential and enable commercial productivity. Hence, this paper takes well X located in KOA oilfield as an example to perform diversion acidizing design by using an independently-developed acidizing software, aiming to provide an insight for efficient development of oilfield in Kazakhstan. Moreover, the investigation on geological reservoir and well logging mainly achieved the following findings: 1. The effective formation thickness and main production layer are 140.1m and 34.8m, respectively. 2. The average oil saturation, permeability, and porosity of main production layer are 81.1%, 0.3md, and 10.6%. 3. Local natural fractures are developed in the formation. According to the formation properties, acidizing numerical simulation shows that diversion acidizing technology can achieve the uniform distribution of acid in the entire production interval. The post-stimulation production of well X reaches 150 ton per day, marking a breakthrough in exploration and development for fractured carbonate reservoir of KOA oilfield.

1. INTRODUCTION
It’s well known that more than 60% of the world’s oil and 40% of the world’s gas reserves are held in carbonate reservoirs, which are the significant domains in oil and gas exploration and development. Matrix acidizing in carbonate reservoirs is one of the most successful methods to bypass the formation damage from the near-wellbore region and decrease the skin. Furthermore, acid- etched wormhole is a typical phenomenon in carbonate matrix acidizing, which determines the acidizing effects. Hence, numerous scholars have performed investigation by numerical simulation and core-flooding experiments [1-5]
For treatments on vertical well with thick formations and strong heterogeneity, acidizing effects mainly depends on the diversion efficiency of acid over the total production interval. Hence, diverting acid systems were widely used in the field application to enhance the stimulation effects. In general, it can be classified into two types: polymer-based and viscoelastic surfactant-based (VES). However, the former usually cause damage after flowback due to the residue of polymer, while the latter will break when it encounters the hydrocarbon, and flowback without any damage to formation. Moreover, the superiority of VES also has been proved by field application [6-11].
Omori Decay of Hydraulic Fracture Induced Seismicity
Authors: Maxwell S. C. 
Published: September 2022

ABSTRACT:
An important consideration for managing induced seismicity is the characterization of seismicity following operational changes made in an attempt to mitigate seismicity. When operational changes are made to control seismicity, ongoing activity associated with earlier activated structure can continue to generate seismicity regardless of the current operational status. It is therefore important to distinguish between ongoing ‘relaxation’ activity associated with a return to geomechanical equilibrium versus continued seismicity associated with ongoing activation and additional perturbation of the seismically active fault. In this paper, three case studies are described demonstrating that seismicity follows an Omori decay, consistent with earthquake aftershock sequences. The Omori decay characteristics thereby provides an important framework to distinguish between fault ‘relaxation’ seismicity and additional activation.

1. INTRODUCTION
Induced seismicity is an important consideration for many industrial activities, including mining, reservoir impoundment, geothermal extraction, petroleum production and subsurface injections. Unconventional reservoir development has recently resulted in an increase in reported cases of induced seismicity (see for example, Schultz et al., 2020), particularly in regions of North America that were previously seismically quiescent. Specifically, hydraulic fracture stimulations and subsurface disposal of produced connate saltwater have both resulted in anomalous seismicity in several regions. Injection induced seismicity results from increased subsurface pore pressure reducing the effective normal clamping stress on preferentially oriented, pre-existing faults (Ellsworth, 2013), triggering slip and associated seismicity along these reactivated faults. In response, regulatory agencies and industry have developed operational guidelines to ensure safe operations, and industry best practices have emerged to mitigate induced seismicity.
Seismicity patterns associated with hydraulic fracturing and saltwater disposal (SWD) typically have distinct patterns (Rubenstein and Mahani, 2015). SWD injections are generally located in the general vicinity of unconventional wells so that water coproduced with hydrocarbons can be safely stored in deep, permeable intervals. SWD wells normally operate for an extended time period resulting in pressure plumes within the target intervals which in some case encounter critically stressed faults that are activated resulting in associated seismicity. Seismicity can occur several kilometers from the causal injection well with variable onset times relative to the start of injection. Cumulative injection effects from interaction of different injection wells can further extend the spatial reach and timing of fault activation and associated seismicity. In general, SWD induced seismicity tends to be relative long lasting, since elevated pressure can persist after injections stop and may appear as a diffuse regional effect around groups of injection wells.
Prediction of Formation Properties Based on Drilling Data of Wells at Utah FORGE Site Using Machine Learning
Authors: Phelan Zachariah , Xing Pengju , Panja Palash , Moore Joseph , McLennan John 
Published: September 2022

ABSTRACT:
This study shows how predictions of formation properties can be obtained from bit-rock interactions without additional operational costs using machine learning models. The models are based on drilling data sets acquired from a highly deviated well at the Utah FORGE (Frontier Observatory for Research in Geothermal Energy) site in south-central Utah, U.S.A. The drilling data is preprocessed by removing outliers that are out of the meaningful range. The data shows that pump pressure and bit RPM are highly correlated with rate of penetration (ROP). Random forest model yields the best performance for ROP prediction with top drive torque as the most important feature. Pump pressure and downhole torque are clustering in different groups for different sections of the inclined well. Successful prediction of confined compressive strength (CCS) is also achieved through random forest model. The model was trained with CCS obtained from sonic logs and calibrated by core test data from a nearby offset well. The well-trained machine learning model can be used to predict CCS of other nearby geothermal wells with drilling data only.

1. INTRODUCTION
Understanding formation properties is important in drilling, completion, and production for geothermal reservoir development. Wireline logs, such as sonic logs, can be used to assess formation properties in oil/gas and geothermal reservoirs. However, logging after drilling can be expensive and is rarely conducted in geothermal wells. Alternatively, predictions of formation properties can be acquired from bit-rock interactions without additional operational costs using machine learning models (Jamshidi et al., 2013; Mahmoud et al., 2021). Drilling and logging contribute a significant portion of cost for Enhanced Geothermal System (EGS). Reliable estimation of formation properties without after-drilling wireline logging would reduce the cost EGS and enhance understanding of geothermal reservoirs.
The drilling data sets investigated were acquired from the Utah FORGE (Frontier Observatory for Research in Geothermal Energy) site in south-central Utah, U.S.A. Utah FORGE is a geothermal field laboratory intended to develop and test tools and technologies required for creating, sustaining, and monitoring EGS reservoirs. Since 2017, five vertical monitoring wells, the deepest to 9500 ft, and a highly deviated injection well, 16A(78)-32, have been drilled. In this study, we focus on the drilling data from the injection well, 16A(78)-32, which is highly deviated at a tangent of 65° to the vertical.
A New Rate of Penetration Prediction Model Based on the XGBoost and Explanation Method
Authors: Chen Gang , Yang Henglin , Yang Dianru , Guo Kaijie , Feng Ming , Wang Yuan , Fu Li , Jiang Hailong 
Published: September 2022

ABSTRACT:
Machine Learning (ML) studies are carried on in the hydrocarbon exploration and production. The Rate of penetration (ROP) is one of the investigations related to ML. Previous studies could not fit the ultra-deep well and most of machine learning ROP prediction are black box models lacking of enough explanation. ML ROP prediction need more accurate ROP models.
In this paper a new and reliable calculation method of ROP prediction for well drilling is proposed by Extreme Gradient Boosting (XGBoost) algorithm. It is compared with Random Forest Regression algorithm on ROP prediction models. According to the importance ranking, rotating torque is the most impacted factor in this dataset. The conclusion is that ROP prediction model based on XGBoost has smaller prediction mean square error and shows higher efficiency than Random Forest, showing the superiority of the XGBoost. Considering the SHAP value ranking, torque and RPM are the most important features and they are positively impacted ROP in well drilling
ROP model established by XGBoost machine learning method can make reasonable use of drilling parameters and provide reference for well drilling optimization. ROP model optimization derived from XGBoost can extremely reduce the expenses by reducing the drilling time.

1. INTRODUCTION
Hydrocarbons, including oil and gas, are often stored in sedimentary rocks in deep formations (Yang et al. 2017). wells are drilled both onshore and offshore with more drilling cost (Ma, Ping, and Jian 2016). One of the most important factors is the Rate of Penetration (ROP) which affect the drilling efficiency and cost (Eskandarian, Bahrami, and Kazemi 2017).
It is difficult to enhance ROP for ultra-deep well drilling as the well depth is increased. Increasing ROP is an approach of drilling optimization and cutting costs by reducing the drilling time. Existing ML models considering less parameters and data points cannot meet current ultra-deep well developing demands. In order to cut costs and increase the amount of drilling operations, finding out the relationship between the ROP and parameters is very important. Make it clear that variables and their relationships with ROP are the main factors which is helpful to promote ROP.
Traditionally instantaneous ROP refers to the drilling footage in time unit, like the data used in this work. And some researchers want to estabilish some models of ROP using drilling parameters. These models can be used to make real time drilling optimization by equipment design guidance and drilling parameters selection.
Geophysical Response of Saturated Rock Joints During Shear
Authors: Han K. , Pyrak-Nolte L. J. , Bobet A. 
Published: September 2022

ABSTRACT:
Monitoring the frictional behavior of rock discontinuities is essential for the identification of potential natural hazards caused by mechanical instability. Active seismic monitoring of changes in transmitted and/or reflected compressional (P) and shear (S) waves has been used as a non-destructive method to assess the degree of damage inside rock and to monitor slip along a discontinuity. The objective of this study is to explore the geophysical response of a saturated rock joint undergoing shear. Laboratory shear tests are conducted on prismatic Indiana limestone specimens. Induced tension fractures resulted in specimens composed of two blocks (152.4 mm × 127.0 mm × 50.8 mm) with rough contact surfaces. Direct shear experiments were performed inside a metal confinement chamber under an effective normal stress of 2 MPa on water-saturated specimens. During the experiments, the chamber pressure, the total normal load, the shear load and the slip displacement were monitored. During the tests, continuous pulses of P-and S-waves were transmitted through the specimen and the amplitudes of the transmitted and reflected waves were recorded. The paper provides results of the mechanical and geophysical response of saturated joints and compares them with those obtained from similar, but dry, joints. For dry joints, both transmitted and reflected P- and S-waves show a distinct peak wave amplitude prior to shear failure. However, for saturated joints, a distinct peak in amplitude is only observed in both transmitted and reflected S-waves. Transmitted and reflected P-waves, propagated through saturated rock, displayed a continuous decrease and increase in amplitude, respectively, but had a sudden change in the rate of amplitude change that can be taken as a seismic precursor to joint shear failure.

1. INTRODUCTION
The stability of a rock mass depends on the presence of pre-existing discontinuities, such as fractures, joints, and faults, and on their response to changes in stress, pressure, fluids and geochemical conditions. The ability to evaluate and assess the mechanical stability and frictional behavior of rock joints has been considered a longstanding goal for the design of geotechnical structures and prevent potential natural hazards. Active seismic monitoring is a non-destructive method to probe inside rock to detect fractures and to monitor their evolution with changes in stress, as well as the degree of damage over time. Changes in transmitted and reflected compressional (P) and shear (S) waves have been used as seismic precursors to shear failure of rock joints (Hedayat et al., 2014a, 2014b, 2018; El Fil et al., 2019, 2021). Recent laboratory experiments have shown that converted waves (S to P & P to S) may be used to track the mechanical behavior of rock joints and detect precursors to shear failure (Nakagawa et al., 2000; El Fil et al., 2021, Gheibi et al, 2021).
Effect of Mineralogy, Pore Geometry, and Fluid Type on the Elastic Properties of the Bakken Formation
Authors: Malki M. L. , Rasouli V. , Saberi M. R. , Mellal I. , Ozotta O. , Sennaoui B. , Chellal H. 
Published: September 2022

ABSTRACT:
The velocity-porosity relationship depends on many factors such as grain shape, sorting, chemical composition, and diagenesis processes. Fluids always occupy the pore space and pore shape plays a significant role in rock stiffness. The Bakken Petroleum System (BPS) in the Williston Basin, North Dakota, consists of the Bakken formation and three folks reservoirs. Bakken formation is divided into three members: Upper Bakken (UB), Lower Bakken (LB), and Middle Bakken (MB), while Three Forks (TF) formation divided into five different units. Although clastic formation’s pores spaces are homogeneous, carbonates present pores heterogeneity which makes their elastic properties estimation complex. This heterogeneity is represented by different pore shapes captured from thin sections, where the aspect ratio (α) defines multiple pore types such as cracks, intergranular, and moldic pores. Furthermore, the pore filling material is a mixture of gas, oil, water, and kerogen in organic-rich shale. This study aims to analyze the effect of mineral composition, pore shape, and fluid type on rock properties of the BPS using various rock physics models. Our results showed that both compressional and shear velocities decreased for all fluid types. We also observed that filling pores with different fluids affect the elastic properties differently, based on their pore geometry, porosity, and lithology.

1. INTRODUCTION
The Bakken Petroleum System (BPS) of the Williston Basin is at the forefront of this new oil boom and contains mature source rocks (the Bakken Shales) and proven reservoirs (Middle Bakken and Three Forks). The BPS is composed of three different formations in ascending order: Three Forks, Bakken, and Lodgepole (LeFever & LeFever, 2005; Nordeng et al., 2010). This would include the upper and parts of the middle Three Forks (Bazzell, 2014). The Bakken formation is divided into nine lithofacies where the upper (UB) and lower Bakken (LB) members are formed from the same lithofacies which is a thinly laminated black organic rich mudstone, while the other eight were identified within the middle Bakken (MB) member (Smith & Bustin, 2000). The UB and LB are mainly composed of illite, silt and clay-size quartz, and orthoclase feldspar. The MB is mainly composed of limestone and sandstone (Smith & Bustin, 2000). The middle Bakken member is characterized by a bigger grain size (sandstone and oolite) and more significant calcite percentages. The Three Forks (TF) consists of mudstones, silty to sandy dolostones, and anhydrites (Gutierrez & Sonnenberg, 2013). The TF Formation is formally divided into five units in which Units 4 and 5 are the primary producing units (Baah, 2015).