bluuebunny/crossref_metadata_2025_split huggingface dataset:
Cementing Technology with Narrow Safety Density Window Based on Wall Shear Stress Theory
Authors: Liu Zhongfei , Wang Chunsheng , Zhou Bo , Gao Haiyang , Chen Jianglin , Zhao Jun , Wang Tianbo 
Published: September 2022

ABSTRACT:
The geological conditions in front of Kuqa piedmont in Tarim Oilfield are extremely complex. High pressure salt water and weak layer coexist in the salt layer, fractures are developed in the target layer, and oil/gas shows are active. Therefore, the contradiction between pressure stabilization and leakage prevention in cementing is prominent. The safety density window of cementing is only about 0.03~0.10g/cm3. Based on the theory of wall shear stress, a set of narrow safe density window cementing technology suitable for Kuqa piedmont front is formed by finely evaluating leakage pressure, optimizing construction displacement and slurry rheological properties, which can effectively improve the cementation quality of cement-stone interface. From 2020 to 2021, more than 40 wells of the narrow safety density window cementing technology will be applied on site, and the cementing qualification rate will be increased by 30%. The effective isolation rate of high-pressure brine and the pass rate of negative pressure channeling test of the target layer are both 100%.At the same time, the managed pressure cementing technology was successfully applied for 7 wells, which provided effective technical support for narrow-density window cementing.

1. INTRODUCTION
The engineering geological conditions of the Tarim Kelasu tectonic belt are complex. The narrow safe density window severely restricts the implementation of techniques to improve displacement efficiency, such as increasing displacement, increasing slurry density difference, and fully circulating wells, making it difficult to guarantee cementing quality. High pressure brine (pressure coefficient 2.30-2.60 g/cm3) and weak layer (pressure bearing capacity between 2.05-2.20 g/cm3) coexist in the piedmont salt layer (Johnston, et al., 1992; Yan, et al., 2019). Fractures are developed in the target layer and the risk of gas channeling is high. In order to stabilize the gas-water layer, the drilling fluid density is forced to increase, resulting in a further narrowing of the safe density window. Some downhole casings are lost or lost, and only positive injection and reverse extrusion can be used. Although reducing the displacement can barely achieve one-time upstroke, the interface cementing quality of the cement sheath is poor, and it is easy to generate micro-annulus. At the same time, in order to safely run the casing under the salt layer to the bottom of the well, some wells use the casing without couplings. In the case that the centralizer cannot be matched, the average degree of the pipe string is only 20%. The eccentric annulus causes poor displacement geometry, and cementing displacement efficiency is more difficult to ensure displacement.
Research on the Prediction Method of Formation Pore Pressure Based on Ensemble Methods
Authors: An J. T. , Huang H. L. , Li J. , Yang H. W. , Gao R. Y. , Zhang G. , Liu P. L. , Luo M. , Li W. T. 
Published: September 2022

ABSTRACT:
Accurately predicting overpressure can effectively guide oil and gas exploration and development. However, the parameterization method is limited by the model form, and the accuracy is low. In this study, a new method to predict pore pressure using ensemble method was proposed. For the first time, acoustic velocity, porosity, mud content, and density were used as input variables and effective stress as output variable, and then accurate prediction of pore pressure was achieved based on the effective stress theorem. Compared with the predictions of traditional models, the performance of the developed models was verified. The results show that compared with the traditional models, the developed method has the advantages of high accuracy, and its absolute average percentage deviation (AAPD), root mean square error (RMSE) are 0.76 % and 0.030 g/cm3, and the coefficient of determination (D2) is 0.992. In addition, the Random Forest (RF) is superior to the Gradient Boosting Machine (GBM) in goodness of fit, generalization and prediction accuracy, which AAPD and RMSE are only 0.13 % and 0.013 g/cm3, and D2 is 0.993. The model developed in this study is not affected by the mechanical depositional environment and is applicable to sandy mudstone formations, such that it can be a useful and highly accurate alternative to the traditional prediction methods with fixed parameter forms.

1. INTRODUCTION
Formation pore pressure, refers to the pressure possessed by the fluid (oil, gas, or water) in the empty space of the formation. During the drilling process, if the pore pressure is accurately predicted, complex downhole accidents such as blowouts and drilling fluid leaks will be effectively reduced and drilling costs will be lowered (Zoback, 2007; Tingay et al., 2009). When the pore pressure is less than the hydrostatic pressure, it is called anomalous low pressure; and when the pore pressure is greater than the hydrostatic pressure, it is called anomalous high pressure (Fig. 1). More than 47.7% oil or gas reservoirs are classified as anomalous high-pressure reservoirs around the world. The mechanisms of anomalous high-pressure genesis include, but are not limited to, the effects of disequilibrium compaction, hydrothermal pressurization, clay mineral transformation, permeation, hydrocarbon generation, hydrocarbon cracking, and pressure transfer. Among these mechanisms, disequilibrium compaction is one of the most dominant loading mechanisms for overpressure formation, and fluid expansion (hydrothermal pressurization, hydrocarbon generation, and hydrocarbon cracking are all part of fluid expansion) is one of the most dominant unloading mechanisms (Vernik. 2016).
Study on the Wellbore Shrinkage During Drilling Operation in Frozen Soil
Authors: Li Y. , Cheng Y. F. , Yan C. L. , Yang H. L. , Gao Q. , Han S. C. 
Published: September 2022

ABSTRACT:
During drilling operations in cold regions, the frozen soil obtains strong creep characteristics, which will result in wellbore shrinkage. An unreasonable drilling fluid density may cause engineering accidents, such as blocking and stuck drills. To solve this problem, a drilling fluid density calculation model based on the power law model of frozen soil creep was established in this paper for controlling the wellbore shrinkage in frozen soil. The factors affecting the wellbore shrinkage rate in frozen soil were analyzed. A map of the wellbore shrinkage and drilling fluid density was also established. The results show that the wellbore shrinkage rate is affected not only by the physical properties of the frozen soil but also factors such as the temperature, formation depth, drilling fluid density, wellbore size, and well opening time. The density of the drilling fluid required for safe drilling in frozen soil increases as the formation depth increases, and the magnitude gradually decreases. As the temperature decreases, the drilling fluid density at the same depth gradually decreases, and the magnitude also gradually decreases. The results provide an important basis for determining the drilling fluid density and the selection of drilling methods in cold regions.

1. INTRODUCTION
As the oil and gas energy situation becomes increasingly severe, unconventional oil and gas is gradually becoming the focus in the petroleum industry. In 2008, the US Bureau of Geodetic Survey conducted exploration in the Arctic and confirmed that the Arctic region is rich in oil and gas resources (Bird et al., 2008). The petroleum industry began to pay attention to the polar regions (Li et al., 2019; Vernikovsky et al., 2013; Sekretov, 2001). Compared with the conventional stratum, there are ice particles in the pores of the frozen soil. The change of temperature and pressure will cause the ice to melt, seepage and secondary solidification, which greatly changes the structure and mechanical properties of the frozen soil and makes the frozen soil own strong creep property. The unique mechanical properties of frozen soil, especially its creep characteristic, would bring a significant impact on drilling operations (Yu et al., 2013; Yang et al., 2010), such as wellbore shrinkage, stuck drilling, and casing could be crushed after cementing. These seriously hinder the exploration and development of oil and gas resources. Therefore, research on the wellbore shrinkage of frozen soil is of great significance for the development of petroleum in cold regions.
Analysis of Cement Plug Bonding Surface Integrity in CO2 Geological Storage
Authors: Dian Wang , Jun Li , Xianbo Liu , Tuo Li , Penglin Liu , Wei Lian 
Published: September 2022

ABSTRACT:
Using depleted oil and gas reservoirs to sequester CO2 is an effective means of mitigating the greenhouse effect. The long-term integrity of the cemented surface of the cement plug is directly related to the risk of CO2 leakage. In this paper, based on the cohesive element method, a new finite element model of cement plug-reservoir-cover is established, considering the sealing location, sealing length, and nature of cementing surface of cement plug. The influence of each factor on the long-term integrity of cementing surface is quantitatively analyzed. The simulation results show that: the cement plug sealing location should be mainly in the cover area, and the minimum length should be not less than 50m; the normal strength and failure displacement of the cemented surface determine the tendency, speed, and height of fracture development, and the fracture development slows down after penetrating the layer. This study is necessary in reducing the leakage risk of CO2 geological storage.

1. INTRODUCTION
Using depleted oil and gas reservoirs to sequester CO2 is a potential method to mitigate the greenhouse effect (Leung et al., 2014). Ensuring the long-term sealing of depleted oil and gas reservoirs is the focus of attention and the key to the success of CO2 geological storage (Shukla et al., 2010; Newell et al., 2013). The types of oil and gas reservoir seal failure can be divided into two categories: wellbore containment barrier seal failure and oil and gas reservoir top cover seal failure (Zhang et al., 2011).
As shown in Fig. 1, the wellbore barrier failure mode can be divided into (1) Formation/cement sheath interface failure, (2) Cement sheath/casing interface failure, (3) Casing/cement plug interface failure, (4) Cement plug body failure, (5) Cement sheath body failure, and (6) Casing body failure according to the CO2 leakage path; For the open hole section, there are two failure ways (1) and (4). (Gasda et al, 2004; Bai et al, 2015; Nagelhout et al, 2010)
Experimental Investigation on the Conductivity of Micro-Frac Dynamic Proppant Transport Process
Authors: Fen Peng , Hongtao Liu , Shiyong Qin , Longcang Huang , Longqiao Hu , Zhikun Pan , Yixuan Liu , Fujian Zhou , Ben Li , Junling Wang , Zhaokun Yuan , Haijun Gao 
Published: September 2022

ABSTRACT:
Fractures are primary flow channels of unconventional oil and gas reservoirs; thus, hydraulic fracturing is widely used to promote the productivity of unconventional formations. Hydraulic fracturing can induce numerous tiny fractures and stimulate some weekly cemented natural fractures. Since the width of the induced fractures is less than 200μm, large size proppants (less than 140 mesh) could not be transported and propped the tiny fractures efficiently. This paper proposed a dynamic proppant transportation and conductivity test method to investigate the flow resistance of the propped tiny fractures. Silica powder, tiny glass beads, and TBA powder were considered potential proppants that could be used to prop the tiny fractures. Proppant diameter and crushing ratio were evaluated. The conductivity of the tiny fractures was evaluated at various slurry concentrations and closure stresses. Results showed that the optimal slurry concentration should not be higher than 9%. Silica powder can be used in higher fracture closure stress formations while TBA and tiny glass beads are more suitable for propping tiny fractures under lower fracture closure stress conditions.

1. INTRODUCTION
As more wells are drilled and completed in the tight formations, operators rely more on small-sized proppants to help ensure the created fractures are propped and to maintain the conductive flow paths for the well production. Micro-proppants may refer to proppants smaller than 100 mesh, mainly including silica flour and ceramic micro-proppant, fly ash are also available.
In 1998, Standard oil applied 100 mesh grains of sand as propping agents in the Upper Morrow formation. Recent studies show that proppants that are smaller than 100 mesh proppants could further improve the permeability of unconventional reservoirs. It was also proposed that microproppant enjoyed a proppant transport benefit into complex fracture systems, in areas where 100 mesh and 40/70 could not travel.
Dahl et al., (2015) undertook permeability tests on split core samples to investigate the effect of micro-sized proppants and tackifying agents in improving secondary fracture conductivity,
3D Geomechanical Modeling for Accurate In-Situ Stress Characterization of a Reservoir in Mahu Oilfield, China
Authors: Xianglong Meng , Yongcun Feng , Wenjun Cai , Shiqi Wang , Wei Yan , Qingping Jiang 
Published: September 2022

ABSTRACT:
Mahu oilfield in Junggar basin is rich in oil and gas resources, because the reservoir has the characteristics of low porosity and permeability, horizontal well and stimulated reservoir volume were applied here. The conventional 1D MEM (mechanical earth model) obtained from single well logging data can not reflect the changes of reservoir geomechanical parameters in long horizontal section, 3D geomechanical modeling is carried out to achieve the fine description of reservoir geomechanical characteristics. During the development of the 3D geomechanical model, a variety of field data and core experimental data were used to ensure its accuracy. The 3D structural model of the reservoir was interpreted from seismic data and a fine description of wave velocity distribution in the 3D model was obtained by a combined interpretation of the acoustic logging data and seismic data. Rock mechanical test data were used to calibrate the predicted geomechanical parameters in the model, ensuring its accuracy. Furthermore, the in-situ stresses determined from diagnostic fracture injection tests and 1D MEM were used to verify the stress calculation results of the 3D geomechanical model. The modeling results show that the direction of the maximum horizontal principal stress in the Mahu oilfield is east to west. The minimum and maximum horizontal principal stresses are in the regions of 42-55 MPa and 63-70 MPa, respectively. There are obvious stress differences between layers, in the range of 10-25 MPa. A comparison of the modeling results against the micro-seismic signals and instantaneous shut-in pressure data recorded during hydraulic fracturing operations further confirmed the reliability of the model. The 3D geomechanical model can provide important guidelines for new drilling and hydraulic fracturing designs in this oilfield.

1. INTRODUCTION
Mahu Oilfield is a large conglomerate tight oil reservoir under development. It is difficult to apply conventional reservoir development methods because of the deep burial of the reservoir, the large natural in-situ stress difference, the low porosity and permeability, and the strong heterogeneity which is caused by the poor particle size sorting of the gravel in the rock mass. In order to realize the efficient development of the Baikouquan Formation conglomerate reservoir in Mahu Oilfield, Mahu Oilfield engineers applied horizontal wells and volumetric hydraulic fracturing based on the idea of multi-layer 3D development.
Exploring Advanced Neural Network Architectures for Synthetic Well Log Generation
Authors: Wong Yian , Wong Sau-Wai 
Published: September 2022

ABSTRACT:
A majority of well logs contain basic petrophysical and lithological values which usually include density, porosity, resistivity, gamma-ray, and customarily, the caliper measurement of borehole diameter to provide an indication of borehole and log quality. Acoustic log acquisition may not be routine, especially in older wells and in cost-constrained environments. Attempts can be made to create synthetic acoustic logs relying on petrophysical and empirical models. However, their reliability and applicability do depend to a large extent on the complexity, variability, and uncertainty of subsurface rocks and fluids. Often, the challenge is compounded by rock heterogeneity such as the highly variable and laminated unconventional shales. In this paper, we tackle the problem of predicting acoustic log response given common well log values such as gamma-ray, resistivity, porosity, and density. Well logs from two very different/contrasting rock formations are used in this exercise. Accurate prediction of acoustic response is shown to be considerably more challenging when rock formation is highly heterogeneous. We consider the generation of synthetic acoustic well log values as a regression task between lithological/petrophysical parameters and acoustic well log values. We survey common machine learning methods in this problem and introduce the use of more advanced techniques. Our methodology includes the adoption of Monte Carlo dropout as a probabilistic inference alternative to regular inference, which allows the quantification of uncertainty in model prediction without having to significantly increase the model’s computational complexity. We survey the performance of all models using two well log datasets, one set of well logs is taken from a relatively homogenous rock formation and the other from a heterogenous rock formation. Out of all models, the proposed Convolutional Neural Network coupled with Monte Carlo dropout provides the most robust results with adequate quantification of prediction uncertainty.
Prediction of Reaming Performance of Vertical Raises Using Rock Properties and Operational Parameters
Authors: Shaterpour-Mamaghani A. , Copur H. , Tumac D. , Balci C. , Erdogan T. , Dogan E. , Altintas E. , Kocbay A. , Sirin O. 
Published: September 2022

ABSTRACT:
Raise Boring Machines (RBMs) as the fast and safe operation of drilling excavation of vertical and/or inclined shafts are used in the mining and construction projects for different purposes. Proper selection and accurate performance prediction of these machines are very important issues affecting the cost estimation and planning of the projects. However, reliable models for predicting performance of these machines have been quite limited. This study aims to develop empirical performance prediction models for vertical reaming operations (unit penetration rate and specific energy parameters) by using physical-mechanical properties of rock samples, operational parameters of pilot hole drilling and reaming. Field performance data of the pilot hole drilling and reaming operations, as well as rock samples, are collected in different raise excavation projects in Turkey. The evaluation indicates that weight on bit of pilot hole drilling with the rotational speed of reaming and static elasticity modulus of the rocks could be used to predict the field specific energy. Consumed reamerhead torque and indirect tensile strength and dynamic elasticity modulus of rocks could be used to predict the unit penetration rate.

1. INTRODUCTION
Raise Boring Machine (RBM) has now become the most preferred machine for drilling / excavation of inclined and vertical shafts in mining and tunnelling projects. RBMs excavate a circular hole between two levels of underground or between an underground level and surface without using explosives and provides improved personnel safety over the drill and blast method as well as a significant reduction in labor requirement. However, the capital investment is higher and higher level of operator training is required (Wake 2000).
RBM uses a small diameter drill rod, around 230-350 mm, to drill a pilot hole down to the required depth. Once the pilot hole has been drilled, the pilot drill bit is removed and replaced with a large diameter reamerhead. The reamerhead is then pulled back up to the upper level by enlarging the hole diameter. In the pilot drilling, the cuttings (muck) are removed from the hole with the aid of flushing. However, in the reaming stage, the muck falls by gravity to the bottom of the hole in where it is continuously removed.
Intelligence-Driven Prediction of Shear Wave Velocity Based on Gated Recurrent Unit Network
Authors: Li Xuechen , Ma Xinfang , Xiao Fengchao , Xiao Cong , Wang Fei , Zhang Shicheng 
Published: September 2022

ABSTRACT:
Accurate shear wave velocity (Vs) is essential for determining reservoir rock mechanical parameters and pore structure of tight oil, whereas it is usually not measured in well logging due to high costs. The simple conversion of compressional wave velocity (Vp) to Vs introduces significant uncertainty to calculation results. To this end, we propose to construct an efficient and robust Vs prediction model using Gated Recurrent Unit (GRU) network, which could deeply mine and connect the information in Vs sequence and other logging sequences (e.g., gamma ray, resistivity, neutron porosity and Vp). Based on the collected logging data set, the GRU prediction model for predicting Vs is trained, validated and tested, which can predict Vs in the missing sections according to synthetic logging data and depth correlation. The optimal hyperparameters of the proposed model, including the number of layers, the number of neurons, activation function and learning rate are explored via the Bayesian optimization algorithm. The field experiment shows that the proposed Vs prediction model outperforms the traditional conversion method and can be used as a promising tool for accurate Vs prediction.

1. INTRODUCTION
The key to the successful development of shale gas and tight oil lies in horizontal drilling and hydraulic fracturing techniques that can break up tight reservoirs for effective connectivity (Junfeng et al., 2015; Longde et al., 2019; Ning et al., 2018; Wendong et al., 2013; Xiaoxia et al., 2014). Notably, rock elasticity, such as Young’s modulus and Poisson’s ratio, plays an important role in the fracturing and production effectiveness of fractured horizontal wells. Most of the parameters characterizing the elastic properties can be calculated from compressional wave velocity (Vp), shear wave velocity (Vs) and density. Currently, Vp and density can usually be easily obtained by conventional logging, but Vs are often missing due to the high cost of the dipole acoustic wave measurements (Gholami et al., 2014; X.-Y. Li & Zhang, 2011; Jun Wang et al., 2020). On the other hand, not only rock elastic properties but Vs is also important for prestack inversion (Pei-Jie & Xing-Yao, 2008), reservoir description (Wegener et al., 2006) and the identification of fluid distribution (Hamada, 2004). Therefore, the urgent need for accurate prediction of Vs has raised the wide interest of foreign and domestic researchers.