bluuebunny/crossref_metadata_2025 huggingface dataset:
Experimental Research on Fracture Propagation of Multi-Well Pad Fracturing Based on Distributed Strain Sensing
Authors: Zhang B. , Guo T. K. , Chen M. , Xue L. R. , Zhang Y. H. , Hu Z. P. , Qu Z. Q.
Published: August 2024

The conventional fracturing mode faces some problems, such as the low complexity of artificial fracture and rapid production decline after fracturing. The multi-well pad fracturing is a crucial technology for effectively developing unconventional reservoirs such as shale and tight sandstone. However, serious interaction exists between fractures when multiple horizontal wells are fractured. Therefore, it is crucial to determine the fracture propagation mechanism in the multi-well pad fracturing. Additionally, the propagation of complex fractures makes it difficult for traditional fracturing monitoring and diagnosis methods to evaluate the hydraulic fracturing operation promptly and effectively. The distributed strain sensing (DSS) technology can evaluate the fracturing effect in real time, which is a hot monitoring technology with an extensive application prospect in horizontal well fracturing. This study combined the DSS with a large-scale (400 mm × 400 mm × 400 mm) true triaxial fracturing device to carry out a three horizontal well preliminary fracturing experiment for the heterogeneous sandstone. Results show that the hydraulic fracture (HF) mainly forms the transverse fracture perpendicular to the direction of the minimum horizontal principal stress (σh). The HF near the well usually crosses the gravel, while the HF tends to bypass the gravel or even be inhibited by the gravel far away from the well. The waterfall diagram of the optic fiber strain can monitor the HF propagation dynamics in real time. Once the HF hits the fiber, the apparent tensile strain can be generated. If the HF deviates from the σh direction, the tension strain will spread to both sides. Under the stress shadow, the later fracturing fracture is prone to extend outside the stress shadow region of the earlier fracturing fracture. The preferential fracturing of intermediate fracture is conducive to exploiting the reservoir resource between the two sides of fractures, so the middle-near-far fracturing method is superior to the far-near-middle fracturing method. This study can provide the reference and guidance for the design of multi-well pad fracturing in oil fields.
Sand Rate in Gas Flow
Authors: Papamichos E. , Varkas M. , Walle L. E. , Berntsen A. N.
Published: August 2024

An experimental study was conducted to investigate the effects of gas flow on sand production. We compared gas flow tests to tests with oil or water flow. In the tests, hollow cylinder Castlegate and Saltwash North sandstone specimens, initially wet or at ambient humidity conditions, were isotropically compressed under simultaneous fluid injection. We carried out both one-phase as well as two-phase flow experiments to simulate important processes encountered in gas fields, like water capillary flow or water-cut. The sand onset results showed that sand onset was delayed in the gas flow experiments. The delayed sand onset, i.e., higher sand onset stress, was related to water evaporation due to gas flow, termed flow-through drying, which strengthens the rock. The sand rate results showed that extensive drying of the rock after long periods of gas flow alters its sand rate behavior. It results in continuous sand production of mostly individual grains and small flakes, owing to low grain cohesion forces in the absence of pore water.

1. INTRODUCTION

Sand production has been a serious concern for the oil and gas industry. It is responsible for erosion of downhole equipment and the need to dispose polluted sand, wellbore instabilities and, in extreme cases, to loss of wells. Sand production, under certain conditions, can also be associated with positive effects on the productivity of a well due to higher applied drawdowns, hole enlargement and removal of the near well damaged zone. The research efforts focused primarily on sand production in oil and/or brine flow as compared to gas flow. However, sand production in gas producing fields has been receiving increasing attention.

Sand production in cemented formations necessitates the mechanical failure of the rock material. This failure occurs when the shear stresses increase above the plastic yielding of the material due to the stress concentration of the effective stress near a well. After mechanical failure, the hydrodynamic force exerted by the flowing fluid on the failed, plastified material leads to erosion and transport of the rock material from the well leaving breakouts behind.
Development and Validation of a New Wellbore Stability Prediction Model for Complex Reservoirs: Application to the Keshen Gas Field in the Tarim Basin
Authors: Liu Yingjun , Xian Chenggang , Zhang Hui , Yin Guoqing , Xu Ke , Wang Zhimin , Lai Shujun , Liang Jingrui , Qian Ziwei
Published: August 2024

The objective of this paper is to propose a new method for predicting the safe mud density window of drilling fluid in the Keshen gas field, located in the Tarim Basin. The study focuses on applying this method to analyze wellbore stability in the complex and high-pressure environment of the field. The new method incorporates the Mogi-Coulomb criterion, which considers intermediate stress as the shear failure criterion of the wellbore. Additionally, the method accounts for the shear breakdown of rock when calculating the fracture pressure. It predicts the shear slip of the reservoir's weak surface using the Jaeger criterion. Furthermore, it takes into account the weak surface of drilling fluid invasion when calculating the tensile failure of the wellbore. The application of wellbore stability analysis in Well A reveals that the dislocation of natural fractures and the tensile fracture after the invasion of drilling fluid are significant factors contributing to wellbore instability, such as chipping and lost circulation, particularly in formations with developed natural fractures. In the case of a strike-slip stress field, shear sliding is more likely to occur when the fluid invades the crack or weak surface, as opposed to tensile failure. Based on the prediction results of the new method, the mechanism of wellbore instability is interpreted, and engineering countermeasures are proposed to mitigate the risk of wellbore instability.

1. INTRODUCTION

The Keshen gas field in Tarim Basin poses significant challenges due to its complex structure, high temperature, high pressure, complicated stress state, and developed natural fractures. These factors contribute to issues such as wellbore instability, a high accident rate, and prolonged drilling periods (Zhang et al., 2015; Cai et al., 2019; Zhu et al., 2014). The primary cause of wellbore instability lies in the disruption of the original mechanical equilibrium near the wellbore, leading to the redistribution and concentration of stress that exceeds the rock's strength once the drill bit penetrates the formation (Nelson et al., 2005; Abbas et al., 2019). The most common manifestations of wellbore instability are collapse and leakage. However, proactive determination of critical mud weights can often mitigate these drilling issues. To achieve this, a constitutive model is employed to estimate the stresses surrounding the wellbore and is complemented by failure criterions. Thus, establishing an accurate and reliable safe mud weights window is of utmost importance.
A Proposed Framework to Estimate Pillar Strength in Room-And-Pillar Hard Rock Mines
Authors: Dzimunya N. Z. , Fujii Y.
Published: August 2024

Pillar strength determination is a fundamental aspect of room-and-pillar mine design. Pillars are left between excavated rooms to maintain stability by restraining the hanging wall. In a typical mining environment, pillars of different rock mass conditions and geological characteristics are cut, resulting in variations in pillar strength. This is because pillars are highly anisotropic and cannot always be formed according to design dimensions. Consequently, unstable pillars may be present, requiring site-specific calibrated methods for ongoing monitoring and strength estimation. Pillar strength determination is typically accomplished using empirical formulae or numerical modelling. Although several numerical codes are available, mine sites still rely on empirical approaches despite their well-known limitations. Empirical methods are popular in the mining industry due to their simplicity. However, it is widely acknowledged that these methods can only be effective within the boundaries of their database and the specific problem scale for which they were designed. In contrast, continual monitoring of pillars and practical experience can enhance pillar strength evaluation. This work briefly describes pillar conditions at a case study mining operation. Additionally, a framework is proposed to estimate pillar strength based on ongoing pillar mapping, risk management decision making, numerical modeling, and analytical hierarchy process.

1. INTRODUCTION

The room-and-pillar mining method is one of the most vital underground ore extraction methods in practice today. In this method, pillars are systematically left in situ to support the overburden weight of the overlying rock mass. If the rooms and pillars are not designed carefully, it can compromise safety or lead to sterilization of the ore reserves.

Designing non-yield pillar systems for shallow hard rock room-and-pillar mines has always been a challenging task. It is important to know the stress distribution in the pillar and the strength of the pillar so that a sound design be produced. Due to the significance of these parameters, extensive research has been conducted on the strength of pillars in hard rocks. However, despite the numerous research outcomes, pillar failures still occur in underground room-and-pillar mines. The literature contains documented examples of such failures and their consequences (Esterhuizen et al., 2006, 2019; Malan, 2012; Ozbay et al., 1995).
Real-Time Prediction of Potential Hazard Area in Seville's During Underground Excavation with EPB
Authors: Bahri Maziyar , Düzgün Sebnem , Mascort-Albea Emilio J. , Romero-Hernández Rocío
Published: August 2024

One of the main challenges in geotechnical engineering involves addressing hazardous areas on the ground surface when conducting underground excavation using Earth Pressure Balance (EPB) in urban areas, particularly those with historical buildings. Given Seville's status as a historic city with ongoing underground metro construction, it is imperative for the city to thoroughly analyze and anticipate any potential hazards that may arise from the excavation process. This study aims to analyze and predict the potential hazard area during the real-time excavation with EPB based on a dataset that is generated in FLAC3D. This dataset contains 100-time steps of underground excavation and 87,034,800 entries. The first 80-time steps of excavation are considered training data, and the last 20 steps of excavation are considered test data. For predicting potential hazard areas, a modified Long Short-Term Memory (LSTM) architecture is employed, with an adjusting threshold for the ground displacement hazard specific to Seville. Consequently, the threshold was systematically modified, ranging from 0.5 to 10 cm. The area under the curve (AUC) values for the 1 and 2 cm thresholds are 0.937 and 0.939, respectively. This finding suggests that this study provides a useful framework for identifying potential risks caused by EPB in Seville.

1. INTRODUCTION

Given the rapid expansion of cities in the 21st century, it is crucial for them to expedite the development of their transportation systems in order to keep up with their increasing demands. Expanding the transportation infrastructure can be achieved by increasing the number of underground tunnels and metros. Nevertheless, excavating more underground tunnels may result in heightened surface displacement and the possibility of harm to buildings (Duranton & Puga, 2013). Controlling ground movements in underground excavation activities is crucial to prevent any potential damage to buildings and structures. Consequently, various studies have been conducted to control these movements using empirical equations, numerical models, and machine learning methods.
A Novel Model for Evaluating Temporary Plugging Effectiveness Between Clusters in Shale Gas Horizontal Wells
Authors: He Le , Zhan Li , Qian Bin , Guan Bin , Ren Yong , Chen Mingzhong , Qu Jianfeng , Liu Yuhao , Zou Longqing , Zhang Yao
Published: August 2024

In order to evaluate the temporary plugging effectiveness between clusters, this study proposes a novel model to calculate perforation opening ratio before and after the introduction of temporary plugging materials. The model is based on the fracturing operation curve and takes into account the perforations erosive effects. Taking Well A and Well B in the Weiyuan area as examples. The research results indicate the following: before the introduction of temporary plugging materials, the perforation opening ratio ranges from 35.1% to 42.5%, after the introduction of temporary plugging materials, the perforation plugging ratio ranges from 30.5% to 46.2%, following the dissolution of temporary plugging materials, the perforation opening ratio ranges from 76.9% to 83.5%. At a displacement of 14 m3/min with a single plugging operation and 12 m3/min with two consecutive plugging operations, the perforation opening ratios are 79.7% and 82.9%, respectively. The perforation opening ratios are comparable under both conditions, therefore, increasing the displacement and reducing the frequency of temporary plugging operations can effectively increase the perforation opening ratio. The model has been successfully applied in more than ten times in the Weiyuan area, providing robust support for the evaluation of temporary plugging effectiveness between clusters.

1. INTRODUCTION

The multi-section and multi-cluster hydraulic fracturing technique in horizontal wells is a crucial technology for shale gas extraction (Zargari et al., 2010; Xu et al 2018) However, factors such as reservoir heterogeneity and stress-shadowing lead to the partial opening of perforation clusters, resulting in incomplete stimulation of the horizontal section (Cramer et al., 2019). The key technology to address these issues is the temporary plugging and diversion (TPDF) fracturing technique. This technique involves introducing temporary plugging materials to plug the already-opened perforations, forcing subsequent fluids to redirect into unopened perforations, creating new fractures, and achieving thorough stimulation of the horizontal section. (Ataur et al., 2017; Leonid et al., 2018; Cyrille et al., 2020).
Finite Element Modeling of Frictional Contact Between a Blunt Tool and Rock with Anisotropic Damage
Authors: Zhou Yaneng , Voyiadjis George Z.
Published: August 2024

The mechanism is investigated for frictional contact between a wear flat and rocks. A brief review focuses on the governing parameters of frictional contact on different types of rocks. Anisotropic damage is taken into account using an anisotropic elasto-plastic-damage model, as demonstrated by a single-element test in uniaxial compression. Anisotropic damage is controlled by a compressive damage coefficient ζ, which can be interpreted as the ratio of axial damage to lateral damage in a special case of uniaxial compression. Tool-rock frictional contact is investigated using a finite element model consisting of a slightly inclined tool and a quasi-brittle rock with induced anisotropic damage. The nature of frictional contact is predominantly governed by three dimensionless parameters: the elastoplastic parameter η, the brittleness number ξ, and the anisotropic compressive damage coefficient ζ. The dimensionless average contact stress (equation) increases with the elastoplastic parameter η, and then slightly varies before leveling off. The contact stress (equation) generally decreases with an increase in the brittleness number ξ. Additionally, the contact stress (equation) increases with a decrease in the damage coefficient ζ from isotropic to anisotropic damage. The numerical results of (equation) are generally consistent with typical experimental results.

1 INTRODUCTION

Tool-rock interactions have important applications in various subsurface operations, such as hydrocarbon production, geothermal exploration, and carbon sequestration (DePaolo and Cole, 2013; Phelan et al., 2022; Li et al., 2023). Different types of tool-rock interactions have been extensively studied from various perspectives, including tool wear, rock failure modes, and material characterization. A wear process is influenced by three components, including the cutting tool, rock properties, and interfacial properties (Hamzaban et al., 2023). The wear of tools increases with increasing applied loads and travel distances, resulting in reduced cutting efficiency (Rostami et al., 2014; Zhou et al., 2017). Different failure modes in rock cutting have been revealed through extensive laboratory tests with both sharp and blunt cutters (Rostamsowlat et al., 2019; Zhang et al., 2022). The mechanisms of tool-rock frictional contact have been investigated using various constitutive models for rocks in numerical modeling (Zhou and Detournay, 2014; Voyiadjis and Zhou, 2019; Zhou and Voyiadjis, 2021). Tool-rock interaction tests also provide a way to characterize material properties of rocks, including uniaxial compressive strength and internal friction angle from scratch tests (Rostamsowlat et al., 2022; Zhang et al., 2022), elastic modulus and hardness from nanoindentation in shales (Liu et al., 2016), and hydraulic diffusivity from indentation in poroelastic and poroelastoplastic rocks (Liu and Huang, 2021).
Probabilistic Stope Stability Analysis Based on the Modified Stability Graph
Authors: de Préval C. Séguineau , Ouellet A. , Andrieux P.
Published: August 2024

The Stability Graph method is widely used to assess the stability of a stope. However, its traditional deterministic application overlooks the variability of the underlying rock mass parameters. By defining distribution functions for the rock mass parameters and running a Monte Carlo analysis on these inputs, the inherent rock mass variability is reflected in the outcome in the form of a distribution of the modified stability number N'. This paper presents guidelines on defining the input distribution functions, and particularly on elaborating the correlation between these distributions. Finally, methods are presented to interpret the obtained modified stability number distribution. The first method introduces a risk tolerance factor allowing to completely determine a stable stope. The second method identifies the drivers for instability, which could be used as variables for subsequent stope optimization.

1. STABILITY GRAPH METHOD

The sizing of open stopes for underground mines is of particular importance during the mine design. Several tools are available to support the engineers throughout the process. One of the most widely used methodology in Canada is the empirical Stability Graph Method, initially developed by Mathews et al. (1981). This method was modified by Potvin (1988) to better account for the specificities of Canadian hard rock mines.

1.1. Modified Stability Graph Method

The Stability Graph Method involves the calculation of two parameters: the modified stability number N′ and the hydraulic radius HR.

The modified stability number is defined as follows:

(equation)

where Q′ is the Q-system rock mass quality as defined by Barton (1974) with the stress reduction and water factors set to 1.0, and A, B and C the rock stress, joint orientation adjustment and surface orientation factors, respectively.

The modified Q′ value is defined by the following equation:

(equation)

with RQD the rock quality designation index, Jn the joint set number, Jr the joint roughness number and Ja the joint alteration number (Barton, 1974).

The three parameters A, B and C are evaluated graphically as shown in figures 1, 2 and 3, respectively.
Investigation of the Failure Mechanisms for Inducing Rock Slope Hazard in New Jersey, United States
Authors: Oppong F. , Khadka P. , Kolawole O.
Published: August 2024

Rock slope stability analysis is of great interest to researchers and engineers due to its potential geo-hazards. This is primarily governed by the shear strength and the acting shear stress which is often expressed in terms of Factor of Safety (FoS) over a potential slip surface. This study investigated the susceptibility of road-cut slopes to rockfall hazard and its associated risks in Northeastern New Jersey, United States, as well as predicted the failure transition to rapid sliding. Four (4) vulnerable rock slopes were identified and demarcated for detailed slope stability analysis. The field data were subjected to three kinematic analyses (planar, toppling, and wedge analyses) using the Dips program in Rocscience software which showed a high potential for both planar and toppling failure and a low potential for wedge failure. The highest risk of failure will be due to toppling failure, with a 26% likelihood of critical failure, which exceeds the acceptable threshold. This indicates that the rock-cut slopes are in unstable conditions and need to be reinforced in the identified locations. It is further recommended that coupled expansive grouted anchor bolts and steel-mesh reinforcement support mechanisms be implemented to strengthen the stability of the cut slopes to prevent rockfalls. This study provides valuable insights for mitigating potential geohazard and the findings here are relevant to other locations across the world..

1. INTRODUCTION

Rockfalls are a major concern in mountainous areas as they can impact both the evolution of steep rocky landscapes and pose significant hazards (Stock and Uhrhammer, 2010; Barlow et al., 2012; Matasci et al., 2017). However, rockfall hazard is not limited to mountainous areas alone. Urban areas are also susceptible to rockfall hazards, particularly where excavations can destabilize slopes and create risks for people and infrastructure (Hungr et al., 2014; Corominas et al., 2017; Gili et al., 2022). Therefore, accurately predicting the areas where rockfalls are likely to occur is crucial for reliable hazard assessment. This requires an understanding of which areas are most likely to be affected by rockfall events (Guzzetti et al., 2003; Corominas et al., 2017; Gili et al., 2022).
Study on RF Heating Mode of Heavy Oil Reservoir Rocks Based on Two Antenna Elements Distributed Along the Horizontal Well
Authors: Wang Zhengxu , Guo Qingfeng , Cai Xiao , Zhang Jingtian , Zhao Qing , Li Bo , Chen Xuefeng , Gao Haiyang
Published: August 2024

To achieve precise heating of reservoir layers with varying thicknesses using the RF (radio frequency) heating method while minimizing thermal energy loss, a novel solution is proposed leveraging a multi-antenna configuration. In this configuration, consisting of two antenna elements, the application of equal and distinct voltages to the antenna elements is categorized based on the diverse characteristics of the reservoir. Additionally, the impact of inter-antenna element distances on temperature profiles was thoroughly examined within these configurations. Research results indicate that these configurations can effectively address varying heat requirements of the reservoir, whether necessitating more, less, or no additional heat, through the adjustment of both distance and voltage. This comprehensive approach offers a viable solution to enhancing the efficiency of heavy oil reservoir heating processes during RF heating in horizontal wells at the operational level.

1. INTRODUCTION

As one of non-conventional hydrocarbon resources, heavy oil reservoirs are widely distributed in the world. Nevertheless, high viscosity prevents the rich resources from being large-scale exploited (Hassanzadeh and Harding, 2016). Besides, with the situation of sustained low oil prices, traditional thermal recovery projects have been terminated because of high production costs and low recovery efficiency (Hasanvand and Golparvar, 2014; Wise and Patterson, 2016). To solve the above problems, oil companies are exploring other alternative heating processes, one of the most promising being radio frequency (RF) heating technology. It is effective in deep, shallow, thin and thick reservoirs, besides the extra energy loss in the pipeline, wellbore and overburden can be avoided (Chhetri and Islam, 2008; Wang et al., 2018).

In recent years, many scholars have investigated the feasibility of RF heating. Ramcharan et al., 2016 explored the viability of using RF heating to extract heavy oil by applying COMSOL Multiphysics and CMG software. Their research results indicated that when an operating frequency of 10 MHz and a current of 50 Amperes were applied, the oil recovery rate was in the range 30-60%. Saeedfar et al., 2016 developed a synthetic homogenous reservoir model to conduct the simulation of RF heating method, and the results revealed that the method had the ability of highly efficient heating of oil sand reservoir.
Fluid Flow in a Fracture Network Under Changing Stresses: A Laboratory Study
Authors: Mei Z. , Li W. , Jin W. , Neupane G. , Atkinson T.
Published: August 2024

Fluid flow in fractured rocks is ubiquitous in natural and human-induced subsurface processes. Subsurface technologies, such as in-situ mining, CO2 storage and geothermal exploitations, require large contact areas between the flowing fluid and the rock to facilitate efficient heat and mass transport and, therefore, ensure the effectiveness of these technologies. Much of the experimental research on fluid flow in fractures has focused on a single fractures in a rock specimen, which leaves the fluid flow in fracture networks under changing stresses largely unexplored. Here, we study fluid flow in a fracture network under changing stresses using a triaxial system. We create the fracture network composed of five orthogonal fractures in rock specimens by assembling six saw-cut rock parts. We measure the overall permeability of the fracture networks under changing vertical and horizontal stresses. We find that the fracture network permeability decreases when the vertical and horizontal stresses both increase. A greater reduction of permeability is observed with increasing horizontal stress than that with increasing vertical stress. We show that this phenomenon results from the larger total area of the vertical fractures than that of the horizontal fractures, making the fracture network more sensitive to horizontal stress changes. Our study shows the importance of the relative orientations between the fractures and the stresses in determining the permeability of the fracture network. This insight can be incorporated to improve the discrete and continuum modeling of fracture networks.

1 INTRODUCTION

Fracture networks are the "highways" for the fluid flow in subsurface rock-fluid systems. They provide a fast path for contaminant transport in fractured aquifers (Tsang and Tsang, 1987; Grisak and Pickens, 1980; Grisak et al., 1980). They could increase the permeability of a geothermal reservoir and, at the same time, reduce the heat extraction efficiency by inducing short-circuiting (Gee et al., 2021). They can also localize the dissolution of porous rocks to the fracture along and induce larger cavities earlier (Li et al., 2021). The overall permeability of a fracture network is affected by the fracture orientation, stress conditions, and fluid pressure. Understanding and predicting the the fracture network permeability as the stresses and pore pressure changes are important for many engineering applications in the subsurface rock-fluid systems.
Equivalent Circulating Density Calculation After Gas Kick Considering Temperature and Pressure
Authors: Jiang Zhenxin , Tao Zhenyu , Wang Zheng , Zhang Wenbo , Liu Yuhan , Liu Jitong , Fu Jing , Fan Honghai , Sun Lewang
Published: August 2024

Deep water is rich in oil and gas resources, which is of great significance to world energy. However, its reservoir geological conditions are complex, the drilling safety density window is narrow, the wellbore pressure is difficult to control, overflow, kick and other accidents are prone to occur, and there are high temperature and high pressure phenomena. In order to deal with a gas kick through managed pressure drilling in time after the gas kick, it is necessary to comprehensively consider the effects of temperature and pressure on the density and rheology of drilling fluid, and accurately calculate the bottom hole ECD after gas kick. Based on the wellbore multiphase flow model and considering the influence of temperature and pressure on the density and rheology of drilling fluid, combined with the special process flow of deep water managed pressure drilling, a more accurate ECD calculation method for deep water managed pressure drilling after gas kick is established in this paper. Verified by the data of well M in a sea area of China, the error of this method is 2% with high accuracy, which provides the basis for field managed pressure drilling.

1. INTRODUCTION

With the development of oil and gas exploration and development technology in the world, the future exploration and development will gradually turn to deep unconventional oil and gas resources. Among them, the reserves of deep water oil and gas resources are rich, which may exceed 70 billion tons. Deepwater oil and gas resources are of great significance to world energy. However, its reservoir geological conditions are complex, the drilling safety density window is narrow, the wellbore pressure is difficult to control, overflow, kick and other accidents are prone to occur, and there are high temperature and high pressure phenomena. (Li, 2021; Li, et al, 2021; Yang, et al, 2023). Managed pressure drilling technology can accurately control the bottom hole pressure and quickly balance the bottom hole pressure difference, which is an important means to solve the drilling problem. (Yin, et al., 2020). ECD, the equivalent circulating density of drilling fluid, is a critical engineering parameter in the process of managed pressure drilling. If managed pressure is inaccurate, overflow and leakage will occur. Providing accurate ECD is the key to the successful implementation of managed pressure drilling. (Liu, et al, 2020; Fan, 2014).
New Understanding of Matrix-Fracture Dual Media Reservoir Damage Based on Pressure-Controlled Fracturing
Authors: Zhang Yang , Qiao Yan , Zhang Shiling , Wu Hongjun , Bai Jie , Guo Xudong , Li Senmu
Published: August 2024

The Tarim Oilfield Krasu tectonic zone is deeply burial, high temperature, low porosity and permeability, and constitutes the complex matrix-fracture dual media seepage channels. Reservoir damage evaluation for such reservoirs is important for subsequent development. In this study, we firstly processed the fracture network in the reservoir core by controlled-pressure fracturing to improve the fracture tortuosity, and verified the reasonableness of this method by CT scanning and shape factor calculation. Then, based on the dual-media condition, we establish the water/oil-lock damage evaluation method, the stress-sensitive evaluation method, the fluid-sensitive evaluation method, and the in-well fluid damage evaluation method. Based on the above methods, the sensitivity of matrix-fracture dual-media reservoirs is moderately strong for water-oil locking, stress, and fluid salinity, moderately weak for liquid alkalinity, weakest for liquid flow rate. In-well fluid damage replacement experiments show that reservoir damage caused by first contact is the most important factor of reservoir damage during the whole process of drilling-completion-reconstruction. For deep tight reservoirs, fracturing fluid is easy to cause serious reservoir damage, and it is necessary to pay attention to reservoir protection during fracturing in low-yield blocks.

1. INTRODUCTION

Reservoir damage is defined as any process that causes a reduction in the natural inherent productivity of gas or oil producing reservoir, or a reduction in the injectivity of a water or gas injection well (Ahmed E. 2021). Reservoir damage is a generic term. It relates to the permeability reduction of a reservoir due to a series of adverse processes (Lucas G. 2012). In the process of oil and gas development, the oil and gas transportation channels are blocked by fluids, stresses and other factors, and the permeability of the reservoir rock decreases (Civan, F., 2000; Radwan, A.E.2019a; Radwan, A.E.2019b). Fomlation damage from drilling and completion fluids can have substantial impact on the productivity of a well (L. Bailey, 1998). During hydraulic fracturing, a large amount of fracturing fluid is retained in the fractures and cannot be discharged, blocking the pores and fractures and reducing the gas relative permeability of the reservoir (Chen et al., 2021; O'Malley et al., 2016; Zhang et al., 2019; King et al., 2012). The main types of fluid damage to reservoirs includes water sensitivity damage, acid sensitivity damage, alkali sensitivity damage and velocity sensitivity damage (Zhou, 2022). Stress sensitivity damage means that after the microfracture closes under the effective stress action, the reservoir filtration capability decreases greatly. And the closed fracture is difficult to open after the effective stress release (Hana, 2022).
De-Risking Stress Testing Operations and Maximizing Injection Longevity
Authors: Karpfinger F. , Donald A. , Gisolf A. , Schlicht P. , Diaz Granados I. , Velez E.
Published: August 2024

A calibrated geomechanical model is one of the key inputs that defines the longevity of carbon capture and sequestration (CCS) projects, ensuring cap rock integrity and maximum reservoir injectivity. The characterization of horizontal stress magnitude is pivotal for model accuracy. Stress testing is the only direct measure of stress magnitudes to calibrate the geomechanical model. The success of stress testing depends on a good understanding of the geomechanical environment and the appropriate choice of equipment. In this paper, we introduce a planning workflow that de-risks the stress testing operations and enables real-time updates of the stress profile. At the end of the stress testing program, the calibrated mechanical earth model (MEM) is then ready to be used as input for defining the injection plan.

1 INTRODUCTION

In the early stage of carbon capture and sequestration (CCS) site characterization, three pillars define if a project has a chance to succeed:

• Capacity–How much CO2 can be stored?

• Injectivity–How fast can CO2 be injected?

• Containment–What is the risk of leakage?

Measuring the minimum horizontal stress magnitude in the caprock and the zone of injection will help to address injectivity and containment. With stricter government regulations for CCS projects, the measurement of the minimum stress becomes increasingly critical. This is also the case for oil & gas field development to enhance hydrocarbon recovery.

The first step in a wireline formation tester stress testing workflow is to determine the feasibility of achieving formation breakdown in a target well for a defined set of downhole equipment. The chance of success (CoS) for formation breakdown along the entire interval will be computed. CoS is defined as the probability of breakdown for a given formation tester and packer specifications at the maximum differential pressure permissible for this equipment. At this stage, accurate model inputs are often not available, and parameter ranges over the full wellbore section can be used as inputs. Parameter uncertainty over the wellbore section is addressed using a probability density function (PDF). Based on the computed CoS for various packer configurations, the hardware will be selected.
CFD Simulation to Study the Grouting Behavior in Rough-Walled Fractures
Authors: Miyoshi T. , Yasuhara H. , Kishida K.
Published: August 2024

In rock engineering projects such as dam and tunnel, rock grouting is performed to increase strength and reduce leakage of the rock mass. In rock grouting, grout materials, typically cement slurry, is injected in rock mass. For jointed rock mass, the cement slurry is considered to flow through the rock fractures as fractures are significantly more permeable than the rock matrix. Although several numerical and experimental works have been conducted to understand the filling and penetration behavior of grouting into rock fractures, the fracture is oftentimes assumed to be a parallel slit, while the aperture of actual fracture is not constant, and exhibits roughness. In this paper, the influences of fracture roughness on the penetration and filling behavior of the cement slurry are investigated through numerical simulation. This is achieved by simulating the grout flow in an idealized sinusoidal fracture with computational fluid dynamics approach. The combined effect of pressure, water-cement ratio, and roughness of the fracture are examined through parametric studies. Based on the simulation results, the insights regarding the penetration behavior and filling behavior of the cement slurry in rough-walled fractures are obtained.

1. INTRODUCTION

In rock engineering projects such as dam and tunnel construction, grouting is performed to increase strength and reduce permeability of the rock mass (Utuski et al. 2013). In grouting, grout materials, typically cement slurry, is injected in rock mass. For jointed rock mass, the cement slurry is considered to flow through the rock fractures as fractures are significantly more permeable than the rock matrix. The measure of the effectiveness of grouting is typically expressed by the penetration length of cement slurry. Therefore, understanding the penetration behavior of the cement slurry is crucial for the grouting design. Gustafson and Stille (1996) estimated the stop distance of cement slurry by solving a force balance equation assuming the cement slurry to be Bingham fluid that is characterized by the shear strength and viscosity. This theory was further developed as a criterion that is applicable in the practical application of grouting design. Although the criterion has been applied extensively in practice, this theory is based on the simplified assumptions that the fracture is a parallel slit, while the aperture of actual fracture is not constant, and exhibits roughness. In terms of the effect of fracture roughness on the fluid flow, previous research has shown that the roughness of fractures has significant effects on the flow behavior of water. However, the influence of roughness on the flow behavior of cement slurry has not been examined in detail.
Failure Mechanism Analysis of CO2 Flooding Wellbore Tubing
Authors: Li Hui , Li Jun , Shan Liping , Lian Wei , Liu Jinlu
Published: August 2024

Carbon dioxide flooding enhanced oil recovery technology has been tested in many major oil fields in the world. It can not only improve oil recovery but also realize long-term geological storage of some carbon dioxide. In the process of low temperature carbon dioxide injection, heat is exchanged with the wellbore assembly, and the ice volume of water in the oil casing annulus expands, resulting in frost heaving force which damages the tubing casing and shorens the life of the wellbore. Based on the theory of fluid-solid heat transfer and phase transformation, a tubing-casing - cement ring - formation assembly model is established in this paper. The damage mechanism of frost heaving force on tubing is studied, and the changes of tubing force and wellbore temperature field under the action of frost heaving force are analyzed. The analysis results show that the frost heave force caused by the freezing of water in the annulus is the main cause of the tubing damage during the low temperature carbon dioxide injection.

1. INTRODUCTION

CO2 flooding enhanced oil recovery technology has been widely tested in major oil fields in the world, and the oil displacement efficiency has been significantly improved, and part of the carbon dioxide geological storage can be realized in the process of oil displacement, which is of great significance to restrain the greenhouse effect. It is also an important part of CCUS. In the process of carbon dioxide flooding, the temperature of liquid carbon dioxide injected at the wellhead is generally 223.15K to 253.15K, and the daily injection volume is 20-40 tons. In the process of low temperature carbon dioxide injection, heat is exchanged with the wellbore assembly. The water in the annulus of tubing and casing will freeze and expand, resulting in frost heave force, which significantly increases the risk of tubing damage increases significantly well integrity being compromised and shortens the life of wellbore. Among them, Sheng li Oilfield in Taizhou, China carried out low-temperature CO2 injection operation for more than two months, and its injection temperature was 253.15K. Practical engineering problems of tubing damage occurred in some test Wells (Fig. 1). According to the field situation, the actual situation of tubing damage in the process of low temperature CO2 injection is known, and the wellbore integrity failure is caused by pipe string damage, and the life of the wellbore is greatly shortened. Therefore, it is of great practical significance to study the failure mechanism of low temperature CO2 injection tubing.
The Determination of Elastic Properties of Laminar Shale Based on Adaptive Threshold Algorithm of Image Segmentation Technology
Authors: Sun Zhengxin , Jin Yan , Guo Xuyang , Luo Jiaqi
Published: August 2024

The characterization of elastic properties of laminar shale is crucial for geomechanical modeling. It plays a vital role in shale gas exploration and development, such as reservoir evaluation, drilling, and hydraulic fracturing. The well-log interpretation has been widely adopted in mineral identification. However, the scale of the log data is more than eight cm per point, and more than the accuracy of the logging data is needed for fine formation analysis. Therefore, this paper proposes an adaptive image segmentation method for predicting elastic parameters based on large thin sections. This method uses an adaptive threshold algorithm to eliminate the noise and improve efficiency in processing relevant boundary information using the finite element method, validated by a numerical uniaxial compression simulation. The results show that the mineral layer's proportion, distribution, and physical properties significantly impact the accuracy of elastic modulus calculations. The deviation between the elastic properties obtained in this study and those obtained through the finite element method is 0.14. This difference can be attributed to the mechanisms determining static and dynamic elastic properties.

1. INTRODUCTION

The physical properties of rocks are mainly determined by mineral composition and distribution. Thin-section identification technology plays a crucial role in evaluating and developing oil and gas resources. It can accurately identify the characteristics of reservoir rocks, the type of diagenesis, and the structural characteristics of reservoir space and pore space (Liu et al., 2021). This technology enables geologists and engineers to understand the physical properties and depositional environments of reservoirs more accurately and thus obtain key parameters of oil and gas reservoirs (Krutko et al., 2019). This is indispensable for formulating oil and gas development strategies and reserve calculations.

The significant advantages of rock thin-section identification are its intuition, speed, simplicity, accuracy and practicality. Through thin-section observation, researchers can directly see rocks' microstructure and mineral composition and thus make accurate judgements on their properties. However, the traditional method of rock thin section identification has certain limitations. It mainly relies on visual observation by experts under an optical microscope, which leads to a huge workload and strain on human resources when faced with a large number of rock samples, may affect the accuracy and quantification of the identification results due to the subjective nature of naked-eye observation. In addition, traditional identification methods require the delivery of physical samples and visual observation, and prolonged preservation may lead to deterioration in the quality of thin sections, thus affecting the accuracy of the identification results.
Research on the Evolution of Fracture Network Considering Anti-Frac Hits of Oilfield
Authors: He Xinru , Zhu Haiyan , Zhao Peng , Chen Shijie , He Xiao , She Chaoyi , Zheng Majia , Wang Dajiang , Li Yuanzhao , Song Junbei
Published: August 2024

Currently, the issue of Frac hits in shale gas wells is prominent, significantly disrupting the production of neighboring wells. In response to the Frac hits in shale hydraulic fracturing, we based on the three-dimensional discontinuous boundary element method, establishes a numerical model of competitive expansion of multiple fractures under different natural fracture parameters. It systematically analyzes the evolution characteristics of fracture networks under stress shadow effects, optimizes fracturing construction parameters, and develops a fracturing network design method to avoid Frac hits. The research results indicate: (1) When the number of perforation clusters in the fracturing section is small, leading to a higher likelihood of Frac hits. When the number of perforation clusters is large, the middle fractures are difficult to extend, and reservoir transformation is ineffective. (2) The possibility of interwell interference increases with a higher density or length of natural fractures. Increasing the injection volume of fracturing fluid restricts the expansion of the hydraulic main fractures, resulting in reduced fracture length, width, and height. (3) To avoid Frac hits while ensuring reservoir transformation effectiveness, a set of fracturing network design method charts is established. This research have significant guiding implications for mitigating Frac hits in deep shale gas reservoirs.

1. INTRODUCTION

This depression belongs to the Cenozoic faulted lake basin of the eastern basin, rich in shale oil and formed in a semi deep-water to deep-water sedimentary environment. These shale layers exhibit typical deep basin lacustrine characteristics and are typical representatives of lacustrine shale oil, with enormous exploration and development potential (Ma et al, 2023). At present, the volume fracturing technology of shale oil and gas horizontal wells has developed rapidly, and basically formed the fracturing technology of "close cutting + sand imposition + temporary plugging and turning". Although the technological progress is very rapid and the stimulation effect is good, the phenomenon of inter-well Frac hits and even casing variation occurs frequently (Zhang et al, 2022).