bluuebunny/crossref_metadata_2025 huggingface dataset:
A Conventional Neural Network Lithology Classification Method Based on Vibration Data
Authors: Chen Gang , Tan Peng , Li Jiran , Jiang Hailong , Fu Li , Yang Henglin
Published: September 2022

Drilling string vibration data is a high-density ancillary data and it has the advantages of low-latency and low-cost which can be acquired in real time. In this study, vibration dataset is used as signal source, and the original vibration signal is filtered by Butterworth (BHPF). vibration time-frequency characteristics are extracted into time frequency images with the application of short-time Fourier transform (STFT). This paper develops lithology classification models using new data sources based on convolutional neural network (CNN) combining with Mobilenet and ResNet. This model is used for complex formation lithology including fine gravel sandstone, fine sandstone and mudstone. In order to improve the trustworthiness of decision-making results, the gradient-weighted class-activated thermal localization map is applied to interpret the results of the model. The final vertification test shows that the single-sample decision time of the model is 10ms, the test macro precision rate is 90.0%, and the macro recall rate is 89.3%. The lithology classification model is more efficiency and accessible. In conclusion, The CNN model using drill string vibration supplies a superior method of lithology classification. This study provides low-latency and low-cost lithology judgment methods to ensure safe and rapid drilling.

1. INTRODUCTION

Lithology classification of underground formation is of great importance in the field of oil & gas exploration engineering as lithology represents the reservoir petrophysical characterization.(Buryakovsky et al. 2012). Vibration data of drill string can also be used to make real time lithology classification considering different formation characteristics. (Esmaeili et al. 2012b)

Some researchers made logging-based lithology prediction by using artificial neural networks. It is demonstrated that lithofacies information from images could be used for lithology classification based on ANN.(Ivchenko et al. 2018) Random Forest is always applied to make underground formation lithology compared with other machine learning algorithms such as GTB, GBM and AdaBoost.(J. Sun et al. 2019) Baraboshkin applied convolutional neural networks on rock description based on color distribution and feature extraction by using different neural network architectures. GoogleNet make a better performance than other algorithms.(Baraboshkin et al. 2020) Ahemd used three machined learning models to predict the lithology changes and formation tops in real-time while drilling including ANN, ANNFIS and FNN, the results shows ANN model shows better performance.
Laboratory Imaging of 2D Hydraulic Fracture Propagation in Laminated Shale
Authors: M. Gu , G. Li , S. Cheng , M. Sheng , S. You , S. Tian
Published: September 2022

Man-made fracture systems caused by hydraulic fracturing is an essential way to improve the success of reservoir stimulation for hydrocarbon production. However, direct observation of reservoir stimulated regions including induced fractures has been difficult. This paper proposed a 2D high-speed imaging scheme for hydraulic fracturing test in the plane strain and in-situ stress conditions. Five bedding angles were taken account to understand the effects of shale anisotropy on hydraulic fracture propagation. The dynamic propagation behaviors and their trajectories were recorded by high-speed camera in 240 Hz. Results indicate the fracture initiation angle is correlated to the shale bedding angle. The fracture initiated along the prefabricated fracture line when β= 30° and 90°. On the contrary, when β= 45°, 60° and 75°, the fracture deviated from the original fracture line and propagated along the bedding direction after initiation of the prefabricated fracture tip, and the induced fracture becomes more likely to divert into the shale bedding direction as the bedding angle becomes larger.

1. INTRODUCTION

Understanding man-made fracture systems caused by hydraulic fracturing is essential to improve the success of reservoir stimulation for hydrocarbon production (Miller, Paneitz, Yakeley, & Evans, 2008). The initiation and propagation of hydraulic fractures are more complex due to the large differences in mechanical properties between shale and sandstone(Dahi-Taleghani & Olson, 2011; Kan & Olson, 2015; Mehrabi, Pei, Haddad, Javadpour, & Sepehrnoori, 2021). As shown in Fig. 1, the interaction of hydraulic fractures with shale bedding structures is the primary cause of complex fracture morphology(Fisher & Warpinski, 2012). The actual fracture height is recognized to be lower than desired value since the shale bedding is activated by hydraulic fracturing(Gao & Ghassemi, 2020; Miskimins & Barree, 2003; Yue, Olson, & Schultz, 2019). It is significant to understand the initiation and propagation behaviors of hydraulic fractures in height by considering the activation of shale bedding structures.
Design and Field Application of Large-Size PDC Bit in Gravel Layer in Tarim Basin
Authors: Bo Zhou , Ning Li , Shenglei Wang , Bao Zhou , Hongjun Liang , Bin Tang , Jinlong Liu , Xueqing Liu
Published: September 2022

It is one of the key difficulties that extremely thick gravel layer distributed in the shallow and middle layers in the Tarim Oilfield. The maximum thickness of the gravel layer is more than 5000m, which seriously restricts the efficient exploration and development of Piedmont tight sandstone oil and gas reservoir. According to the characteristics of gravel layer in Bozi block, this paper selects the appropriate outcrop, studies the parameters such as conglomerate composition, hardness and compressive strength through rock mechanics experiments, and summarizes the diagenetic characteristics of gravel layer in Bozi block. The experimental results show that there are great differences in mineral composition in the plane of rock samples and a wide range of spatial strength variation, so the impact load on the bit during drilling is large. According to the results of experiments, a new large-size PDC bit is designed from optimization of cutters, tooth arrangement and force balance design. The designed large-size PDC bit has obvious effect of speed-up, which achieves the footage of a single bit is 510m, and the ROP(rate of penetration) is 1.89m/h. Compared with adjacent wells with the same lithology in the same well section, the footage and average ROP of a single bit are doubled, which achieves a good speed-up effect, and provides technical reference and support for efficient exploration and development of oil and gas reservoir in the Tarim Basin.

1. INTRODUCTION

Huge thick gravel layer is developed in the upper part of Kelasu structural belt in Kuqa depression, Tarim, especially in Bozi block. The average thickness of gravel layer is 3000m and the maximum thickness is more than 5000m(Teng et al., 2015; Zhong et al., 2012). Multiple sets of strata contain gravels with different compositions, which are poor sorting, strong heterogeneity and poor drillability. During the drilling process, cutting teeth of conventional PDC bits are easy damaged due to the positive impact of gravel. The damage of PDC teeth leads to slow ROP(rate of penetration), less bit footage and more bit consumption(Pei, Yan, & Hongbo, 2020; Zhang, Dang, Chen, & Zhang, 2017), that seriously restricts the efficient exploration and development of oil and gas reservoir.
Damage Character and Fracture Propagation Study of Longmaxi Shale in Southern Sichuan Basin During Hydraulic Fracturing
Authors: Fu Li , Yang Henglin , Xi Yunlong , Chen Gang , Zhang Guangqing , Lv Yanjun
Published: September 2022

Longmaxi S1l11 layer is main shale gas reservoir formation in southern Sichuan Basin, the difference of sublayer post-fracture response is significant. In this paper, we make triaxial tests with Longmaxi shale samples from southern Sichuan Basin layers to study damage character during hydraulic fracturing. Cohesive unit numerical simulation method is used to study the characteristics of hydraulic fracture (HF) propagation considering shale damage. The results show that in Longmaxi shale compression damage is divided into three stages: compaction, linear damage and rock failure. Reservoir shale damage due to HF concentrated in the linear damage stage. The degree of S1I13, S1I14 shale damage is greater than that of S1I11, S1I12 shale with the same strain. Fracture propagate straight into S1I12 layer after S1I11 layer fracture initiation, most fractures propagate into S1I11 layer, and few fractures propagate into S1I13 layer after S1I12 layer fracture initiation, which is the similar HF in S1I13 layer. The fracture propagation of S1I11 and S1I12 layers is highly sensitive to the liquid injection displacement. With the increase of liquid injection displacement, the total length of the fracture increases significantly and the number of damage and failure units increases significantly. During HF propagation, more plane bedding and natural weak surfaces can be better connected and opened to form more branch fractures; The fracture propagations of S1I13 and S1I14 sublayers are highly sensitive to the liquid injection displacement. With the increase of liquid injection displacement, the total length of fractures and the number of damage and failure units are significantly reduced. During the fracture propagation of S1I13 and S1I14 sublayers, the fracture shape is relatively straight, and only a small amount of plane bedding and natural weak surfaces in the formation are connected and opened, forming a small number of inconspicuous branch fractures.
Fracture Opening Patterns in Granular Media Subjected to Injection of Non-Newtonian Fluids
Authors: Li Zihao , Song Haofeng , Balhoff Matthew T. , Espinoza D. Nicolas
Published: September 2022

Fluid injection into sand may initiate fluid-driven fractures. The fluid-sand interaction patterns depend on the injection velocity, fluid viscosity, rheology and stress boundary conditions. However, the extension to non-Newtonian fluids and anisotropic stress conditions, such as in the case of injection of a polymer in the subsurface, is largely unexplored. In this paper, we study the injection of a Newtonian fluid (glycerol aqueous solution) and a shear-thinning fluid (scleroglucan) into a sand-filled Hele-Shaw cell. The experimental results demonstrate complex fracture patterns depending on injection velocity, fluid viscosity, boundary conditions and fluid rheology. The presence of stress-free boundaries causes the fracture opening to be almost perpendicular to the minimum principal stress. The peak injection pressure is also higher compared to the fixed-displacement boundaries. Compared to Newtonian fluid (glycerol), shear thinning polymer (scleroglucan) causes thinner fracture openings and more radial infiltration morphology in sand. The fracturing mechanism in sand is associated with the shear dilation at the tip of fractures and fracture offshoots. This study helps to clarify the basic flow and failure mechanisms of sand when subjected to injection of a non-Newtonian fluid. The insights obtained from these experiments can aid in the prediction of fracture morphology and sweep efficiency for on-site polymer injection.

1. INTRODUCTION

Hydro-mechanical interactions between fluid flow and solids are common in many industries, such as oil and gas exploration, formation damage caused by particle jamming during oil and gas production (Li et al., 2021a), hydraulic fracturing (Zheng et al., 2020; Zheng and Sharma, 2021, Li et al., 2020), spray coating processes in food processing (Hilton et al., 2013) and tablet production in pharmaceuticals (Hemamanjushree and Tippavajhala, 2020). Different fluid infiltration and fracture opening morphologies caused by the injection of Newtonian fluids affect the fluid injectivity (Li et al., 2021b). However, extensions to non-Newtonian fluids and anisotropic stress conditions, such as in the case of injection of polymers in geological formations, are largely unexplored.
A Visualization Study of Fracture Propagation in Tight Sandstone Under Triaxial Loading
Authors: Zang Y. X. , Wang Q. , Tian K. J. , Wang H. Z. , Tian S. C.
Published: September 2022

Hydraulic fracturing is the key technique in the development of unconventional resources. Many optical experimental studies have been made to qualitatively study the hydraulic fracturing process. However, due to the time of fracture propagation being extremely short (ms), real-time quantitative description of the fracturing process is challenging. To clarify the process of fracture propagation, a novel triaxial optical hydraulic fracturing experimental apparatus is developed which mainly includes an ISCO displacement pump, triaxial servo control devices, high-intensity illumination devices, high-speed camera, and data acquisition systems. The fracturing process could be captured visually in real-time by using a high-resolution camera. This study also proposes an accurate and effective analysis method, Digital Image Correlation (DIC), for characterizing fracture and measuring the strain field. The results show that the pressure-time curve of hydraulic fracturing can be divided into three stages: pressure rise stage, the crack initiation and propagation stage, and the pressure plateau stage; the initiation pressures of water and CO2 fracturing in tight sandstone are 10.1 MPa and 5.2 MPa respectively; hydraulic fractures active the natural fractures, resulting in a complex fracture network structure; hydraulic fractures will turn and gradually become vertical to the minimum principal stress during the extension process. The results of this paper can provide guidance for the field application of hydraulic fracturing in tight sandstone resources.

1. INTRODUCTION

With the rapid development of the economy, the energy demand has increased rapidly, and unconventional oil and gas resources such as tight gas, coalbed methane, and shale gas have become an important guarantee for the national energy strategy1. Hydraulic fracturing technology is an important technology for the exploitation of unconventional oil and gas resources2, among which the geometry of hydraulic fractures is the key to evaluating hydraulic fracturing operations, still needs further research3-7.
Fully Coupled Thermo-Hydro-Mechanical Model for Wellbore Stability Analysis of a CBM Horizontal Well
Authors: Liu Jinhua , Ma Tianshou , Fu Jianhong , Fan Xiangyu , Zhang Qiangui
Published: September 2022

Due to the influence of drilling disturbance, wellbore collapse frequently occurs in the underbalanced drilling process of coalbed methane (CBM) horizontal wells. In fact, this kind of wellbore collapse problem is influenced and controlled by the thermo-hydro-mechanical (T-H-M) coupling effect and coal shrinkage induced by methane desorption that happened in the underbalanced condition. However, most previous studies ignored the influence of T-H-M coupling and coal shrinkage on wellbore stability. Therefore, a fully coupled T-H-M model with local thermal equilibrium condition was proposed for wellbore stability analysis of a CBM horizontal well, where the coal shrinkage induced by methane desorption was taken into account, and the finite element method was employed to solve the present model. The changes of the time-dependent field variables, such as pore pressure, temperature, and stress components were analyzed with considering different coupling conditions. The failure behaviors of a horizontal wellbore in different coupling conditions were also analyzed and compared with the results of the traditional analyzing method. The results indicated that both T-H-M coupling and coal shrinkage induced by gas desorption have a significant impact on these time-dependent field variables and failure behaviors of horizontal wellbore, in other words, the effect of gas desorption and T-H-M coupling cannot be ignored in CBM underbalanced drilling. Thus, the present model can help us understand the multiple fields coupling behaviors around the CBM horizontal wellbore in underbalanced drilling, and it can also provide the theoretical basis for predicting collapse pressure accurately, optimizing drilling mud density and maintaining wellbore stability.

1. INTRODUCTION

Coalbed methane (CBM) is considered to be a kind of significant unconventional natural gas resource, and a large amount of attention has been paid to it worldwide (Palmer 2010; Moore 2012). Nowadays, underground gas drainage and surface drilling are the two main technologies to develop CBM from coal seam (Shen et al. 2012; Thakur et al. 2014). Depends on the development of drilling technology, CBM surface drilling technology has developed very rapidly in recent years. And the horizontal drilling technology from the surface is now considered to be the most efficient technology for extracting CBM, which has the advantage of much higher safety, economy and much more reservoir stimulation measures (Tao et al. 2019).
Analysis of Low-Pressure Operation Stability of Underground Hydrogen Storage Salt Cavern
Authors: Dong Jingnan , Zhuang Xiaoqian , Gong Danni , Ban Fansheng , Zhang Yingbin
Published: September 2022

In order to meet today’s increasing fluctuations in energy demand, large-scale underground salt rock gas storage is widely used in the storage of fuels, including natural gas, oil and hydrogen. From the perspective of macroscopic structure and stratigraphic structure, the Jintan salt deposit in China has good sealing properties, and is an ideal solution mining area for the construction of salt rock gas storage. Salt rock has extremely low permeability and self-repairing properties, which greatly increase the sealing performance of the gas storage. Underground salt cavern hydrogen storage has been proved feasible in some area worldwide. The molecular weight of hydrogen is extremely low, so it has high requirements on the sealing performance of hydrogen storage, especially in terms of long-time storage. In this paper, two geo-mechanical models are established as one single-cavern configuration and 4-cavern configuration to analyze the stability of the hydrogen storage in terms of cavity volume shrinkage, stress distribution of rock mass around caverns, and surface subsidence. Through numerical simulation using FLAC3D, the evolution law under long-time low-pressure conditions is investigated. The tightness and stability of the trap conditions of the salt interval are studied, and the reasonable low operating pressure range of the salt rock hydrogen storage is proposed. The study found that under the condition of ensuring the stability of the salt cavity, the gas storage should keep the operating pressure from 8 MPa to 9 MPa at the depth around 800 to 1000 m. The long-term constant pressure operation at lower and higher limit did not see obvious salt cavity tensile stress concentration areas within 30 years, and the salt cavity expansion area was concentrated in the local area. For most salt cavern hydrogen storages of 800 to 1000 meters depth, 8.27 MPa is an acceptable operational pressure. Considering the surface subsidence, it is necessary to pay more attention when multi cavern configuration is applied. An increase in the amount of underground space will lead to large surface subsidence. This study provides guidance for the hydrogen underground salt cavern construction in bedded salt.
Some Attempts on Characterization and Evaluation of Properties of Fracture/Shear Zones
Authors: Aydan Ö. , Kumsar H. , Iwata N. , Ulusay R.
Published: September 2022

This study is concerned with main causes of fault/shear formation and the utilization of various experimental techniques for their evaluating mechanical properties. In the first part, the results of several experimental studies on the formation of fault/shear zones are presented. Then, some proposals have been done how to characterize the geometry, fracturing, morphology, and internal structure of fault/shear zones and some examples are given using some rock classifications. Then, some direct shear tests were performed on the actual fault gouges and their actual characteristics have been evaluated. The characterization and evaluation of the properties of fault/shear zones using RMQR rock classification method are explored. In addition, the utilization of conventional and modified Needle Penetration Index (NPI) for assessing the characteristics of fault/shear core is investigated. Finally, the presented procedures and techniques are applied to actual fault/shear zones and they are validated.

1. INTRODUCTION

Fault/shear zones commonly exist in Earth’s crust and they may be encountered almost in all engineering projects. They may cause very severe engineering problems such as heavy water in-flow, squeezing, instability. They may be pathways for leakage of radio-active wastes to the environment as shown in Figure 1.

Many fundamental studies on fracture/shear zones have been done by various researchers (e.g., Cloos, 1930, 1968; Tchalenko, 1970; Roth et al. 1981; Tsuneishi, 1978). Hubbert (1951) and Hafner (1951) were first to give the first theoretical treatise of fracture/shear formations in non-cohesive materials. In engineering applications, some studies were concerned how to locate important structures outside the potential rupture zones (e.g. Cole and Lade, 1984a,b; Bray et al. 1992).

Many experimental studies on hydro-mechanical properties of fractures zones and faults in several institutes (e.g. Byerlee 1990, Kutter and Rautenberg, 1979; Lama 1978; Moore et al. 1983; Rutter et al. 1986; Archambault et al. 1990). They tested several types of gouges found in fractured zones and faults under different environmental conditions such a normal pressure, temperature, water content, loading rate.
Evaluation of the Timing of Different Stages of Collaborative Construction of Underground Gas Storage and Natural Gas Flooding
Authors: Fuguo Yin , Shiqing Cheng , Dengke Shi , Penglin Liu , Rui Zhou
Published: September 2022

An underground gas storage (UGS) rebuilt from oil reservoir is constructed in collaboration with natural gas flooding, which is a new type of UGS developed in recent years and is called collaborative type UGS. The collaborative type UGS aims to improve the recovery of the original reservoir as much as possible while building the UGS. At present, the construction process of cooperative type UGS has been divided into three stages: oil displacement, collaboration and UGS. However, the transition time node of different stages is still fuzzy, which is very important for the construction of collaborative type UGS. Therefore, in order to clarify the starting time nodes of each state of collaborative type UGS construction, a method is proposed to dividing stages of collaborative type UGS construction based on the full research of cases which the UGS were converted form the oil reservoirs. On the basis of this classification method, a new analytical model of injected gas volume in different construction stages is build based on a new type of gas flooding characteristic curve and material balance method. Finally, we confirmed that our model is well suited for collaborative type UGS. The predicted production of our model is very close compared to the actual production data, and thus the methodology should be attractive to the industry. This study extends existing analytical model methodology for collaborative type UGS and is relatively easy for reservoir engineers to understand.

1. INTRODUCTION

Underground gas storage (UGS) is a kind of artificial gas field or gas reservoir formed by injecting commercial natural gas transported by long distance pipeline into underground space. It has important functions such as regulating gas supply in different seasons, strategic energy reserve and obtaining economic benefits. According to statistics from the latest World Natural Gas Congress (GIOUSE, 2018), a total of 689 underground gas storage facilities have been built around the world, with the total working gas volume accounting for 11.8% of the total annual consumption of natural gas. There are 4 types of reservoirs commonly used for underground gas storage 1) oil reservoir 2) gas reservoir 3) aquifer and 4) salt cavern, each of the storage reservoirs has very specific producing parameters (Ding, 2011; Jiang, 2021;). Figure 1 shows the proportion of working gas in different types of underground gas storage.
Utilization of Impression Creep Tests as Index Testing Technique in Rock Mechanics and Rock Engineering
Authors: Aydan Ö. , Ito T. , Özcan N. T. , Rassouli F. , Özkan Í.
Published: September 2022

Impression creep devices capable of applying a tip pressure up to 134 MPa for an indenter of 3 mm in diameter as an index creep testing technique was developed by the authors. In this study, a new monitoring system utilized in the impression creep devices is described and its utilization for evaluating creep responses of rock salt samples from Çankin and Tuzköy in Nevçehir Provinces of Turkey and Oya tuff from Tochigi Prefecture in Japan are presented and discussed. The experimental results obtained from impression creep tests are compared with those from conventional creep tests and the suitability of impression creep tests as an index test is explored. The most critical issue in creep tests is the determination of stress level. This issue is investigated theoretically and experimentally. It is suggested the short-term impression test can be utilized for determination of the stress level in impression creep tests. The experimental results clearly demonstrated that both conventional and index tests could be quite comparable and similar type responses are observed and it is concluded that there is a high possibility for the utilization of the impression creep as an index creep test.

INTRODUCTION

Creep experiments are of paramount importance for assessing the long-term stability of rock engineering structures. ISRM (2007) recognized this issue and a Suggested Method for Creep Test was developed (Aydan et al 2014a). The creep tests have been used in the field of rock mechanics and rock engineering for decades (e.g., Jaeger and Cook 1979; Aydan et al. 2011, 2014a, 2016; Aydan 2016). Apparatuses for creep tests can be of cantilever-type or load/displacement-controlled type. The major issue in creep tests is keeping sustained loading on samples and monitoring of displacement and other parameters throughout experiments without any interruptions.

The authors involved with the methods for creep tests under indirect tensile stress regime of Brazilian test, uniaxial and triaxial compression tests and direct shear tests, to determine the creep characteristics of rocks. Ito et al. (2021) have recently developed a new monitoring system for continuous measurement of displacement, acoustic emissions in addition to environmental parameters and utilized in uniaxial compression, Brazilian tensile and bending tests. It is shown that the new monitoring system can measure long-term responses without requiring any conventional power system.
Impact of Stress Concentration of Pores on Shale Gas Production
Authors: Peng Yan , Shen Liji , Lv Peihong , Wei Shengjie , Wang Xiaohan
Published: September 2022

Shale gas reservoirs have extreme low permeability which changes with stress variation. Numerical simulation results show that the stress-dependent permeability sharply affects shale gas production. Common permeability model indicates that the stress-dependent behavior of permeability results from pore volume change which is calculated by the equation for rock solid phase. Generally, pores are void inside rocks and the stress concentration should be generated around pores but the common model fails to consider this impact. In this paper, the permeability model with impact of stress concentration is used in the flow-geomechanics coupled numerical simulation for shale gas production. This numerical simulation model is validated by field data. After that, several factors affecting shale gas production are analyzed. The results show that (a) the error of shale gas production rate between prediction result and field data within 10%; (2) the difference between production rates predicted through the new model can be over 67% because the stress alternation behavior in real reservoir is different to the one in laboratory; (3) the impact of stress orientation on shale gas production is few and the difference of accumulative production is only 4.3% when the stress orientation changes from 0 ° to 40°. Those results indicate that (1) the model with impact of stress concentration is valid for shale gas production; (2) if the alternations of stress components are different, stress concentration significantly affects shale gas production.

1. INTRODUCTION

Unconventional oil and gas resources have become essential parts of the global oil and gas supply. Global unconventional oil and gas production is expected to account for more than 20% of the total output in 2030 (Zou et al., 2013). The successful development of shale gas reservoir benefits from horizontal well and large-scale hydraulic fracturing (HF)technology, making shale gas exploitation become an essential direction of unconventional natural gas development(Ding et al., 2014; Du et al., 2017).
Numerical Simulation on Characteristics of Hydraulic Fracture Initiation Induced by Circle Pumping Method
Authors: Peng Yan , Wei Shengjie , Lv Peihong
Published: September 2022

Hydraulic fracturing is an important treatment for tight reservoirs, however, it may induce high initiation pressure of fracture or generate a hydraulic fracture with simple shape. In order to increase hydraulic fracture efficiency, recently, the fatigue hydraulic fracturing method is proposed by several scholars. Experimental data show that this method can generate complicated hydraulic fractures, reduce initiation pressure, reduce magnitude of seismicity and increase permeability. Using the circle pumping schedule is a method to generate the fatigue loading inside hydraulic fractures. In this paper, a flow-geomechanics coupled numerical simulation model is first built. This coupled model has two governing equations. The first governing equation is the transient flow model (TFM) which is used to describe the flow behavior of fluid inside hydraulic fractures. The second governing equation is the rock deformation equation which is used to calculate the stress solution of rocks. The maximum tensile criterion is used to judge whether the hydraulic fracture can be generated. Several factors affecting fluid flow and hydraulic fracture initiation are analyzed by this numerical simulation model. The results show that (1) The circle pumping schedule can initiate new fractures around the hydraulic fracture. This pumping schedule induces heterogeneous distribution of fracture pressure and further induces tensile stress in several locations. This tensile stress initiates new fracture. (2) input pressure amplitude, frequency, roughness and viscosity affect hydraulic fracture initiation.

1. INTRODUCTION

The success of unconventional reservoir development is the benefits of hydraulic fracturing and horizontal wells (Rong et al.,2004; Karacan et al., 2011; Dong et al., 2019; Nguyen et al., 2020; Wang et al., 2020; Zhang et al., 2020;). The production rate of the unconventional reservoirs increases with stimulated reservoir volume (SRV) induced by hydraulic fracturing. In order to reduce initiation pressure and magnitude of seismicity but increase the SRV, the circle pumping hydraulic fracturing method (CPHFM) has been proposed and investigated. The HFST results show that the production rate of shale oil reservoir is increased by 10% when the CPHFM is used (Ciezobka et al., 2018). The borehole pressure generated by the CPHFM is higher than the one by ordinary method so the extra hydraulic fractures is initiated around perforations(Ciezobka et al., 2018).
Experiment Investigation on the Fracture Initiation Characteristics of Shale Saturated with CO2 and Brine
Authors: Tian G. , Wang H. , Li G. , Yang B. , Zhao C. , Zheng Y.
Published: September 2022

Supercritical CO2 (SC-CO2) is regarded as a promising fracturing medium to exploit unconventional oil and gas resources. However, the reactions between CO2-brine-rock would change the mechanical properties and microstructure of rocks during SC-CO2 fracturing. To explore how the reactions affect the hydraulic fracture initiation and propagation, a series of fracturing experiments on shale saturated with CO2 or/and brine are carried out in this study. Experimental results show that the initiation pressures of rocks was reduced by 11.2 MPa after CO2 and brine saturation. Compared with dry shale and samples saturated with brine only, the initiation pressures of specimens after SC-CO2 and brine saturation reduce more significantly owing to the deterioration of mechanical properties by SC-CO2. And the fracture pattern of shale after treatment is more complex. Both tension and shear fractures are present and the fractures intersect and deflect.Moreover, fractures induced by the SC-CO2 fracturing of the untreated shale are more complex and rough than those in saturated brine and CO2. The arithmetic mean height, root-mean-square height, the maximum height and the fractal dimension of the crack surface of shale saturated with brine and CO2 decreased by 59.2%, 57.6%, 52.5% and 7.8%, respectively. The experimental results can provide laboratory evidence for the implementation of well-soaking before SC-CO2 fracturing.

1. INTRODUCTION

With the rapid development of the world economy, it is difficult for conventional oil and gas resources to meet the increasing energy demand (Hosseini et al., 2019). Countries have turned their attention to unconventional oil and gas development. Due to the dense matrix and poor physical properties of unconventional reservoirs, horizontal wells and large-scale hydraulic fracturing are required to realize efficient development (Lampe & Stolz, 2015; Soliman & Kabir, 2012). The application of clear water fracturing and slickwater fracturing in North America has successfully advanced the revolution in shale oil and gas development (Le, 2018). However, traditional hydraulic fracturing has a series of shortcomings, such as reservoir pollution, high cost, waste of water resources, difficulty in the treatment of flow-back fluid, and so on (DiStefano et al., 2019). As a result, some countries have begun to ban the use of hydraulic fracturing. For example, the French government has passed legislation prohibiting the use of hydraulic fracturing for shale gas production (Chailleux et al., 2018). Aiming at the environmental protection concept of sustainable development, it is urgent to explore clean and efficient fracturing technology. SC-CO2 fracturing can avoid the above problems and realize CO2 geological storage while efficiently exploiting oil and gas, attracting a lot of attention (Wang et al., 2012, Zhou et al., 2019).
Experimental and Numerical Evaluation of the Integrity of Cement and Geopolymer Under Low and Elevated Temperature Well Conditions
Authors: Ogienagbon A. , Khalifeh M. , Wu Y. , Salehi S.
Published: September 2022

Wellbores constructed in high-temperature environments require more reliable cement systems to overcome complicated near-borehole loads. In this study, we numerically evaluate the effect of temperature on the interfacial bond integrity of two cementitious materials - an industrial class expansive cement and a rock-based geopolymer based on their experimental triaxial test properties. The results from the triaxial test indicate that the test temperature did not have a significant impact on the mechanical properties of both types of materials except for the confined compressive strength. Geopolymer showed higher flexibility, higher Poisson’s ratio, and lower compressive strength than the industrial class expansive cement at both temperatures. From the numerical analysis, the results show that the most likely cement failure location is at 90° to the maximum in-situ stress on the casing-cement interface. Without considering pore pressure effects, cement crushing resulting from excessive compressive stress is the main reason for the inner interfacial debonding. The test temperature has a significant influence on hoop stress. High test temperature results 13 – 45% increase in the hoop stress. Radial stress was insignificantly influenced by the test temperature. When test temperature changes from 30 to 90°C, geopolymer experiences an 80% increase in hoop stress while the industrial class expansive cement only experiences a 1% increase.

1. INTRODUCTION

Cement is one of the major barrier elements for maintaining well integrity. It is conventionally used for in primary, remedial and plug and abandonment operations. The loss of well integrity can lead to environmental risks, economic losses for the operator and even safety issues. Several factors can compromise cement integrity during its placement, these include but are not limited to poor cement displacement, fluid loss, mud contamination, etc. Despite the completion of a good cement job, fissures, cracks and microannuli may still develop long after well completion.
Mechanical Properties of Shales Mapped at the Nanometer Scale
Authors: Wang Qisheng , Wang Tianyu , Zhong Pengjun , Verdiyev Gorkhmaz , Zhang Panpan , Tian Shouceng
Published: September 2022

The mechanical properties of organic matter (OM) strongly affect the way shales deform and fracture. Lack of knowledge regarding mechanical properties of OM in fine grained rocks mainly because it often occupies tiny nanometer-scale voids between the mineral grains. In this study, scanning electron microscope (SEM), energy dispersive spectrometer (EDS), and atom force microscope (AFM) are used to measure the micromechanical properties of the shale. Then, the pyrite, feldspar, quartz, clay, calcite and OM are organized as the shale minerals database. The OM of the belt-like mechanical properties is found. Meanwhile, the greater the gray value (brighter) of the OM SEM image, the greater the elastic modulus of OM are. We propose a standalone software, the distribution, mean modulus, mean deformation and proportion of each minerals can be calculated by AFM In-Suit Identified software. These findings help understand the properties of organic-rich sedimentary rocks from a microscale perspective and provide the fundamentals for fracturing.

1. INTRODUCTION

Organic-rich shales have been commercially exploited with the hydraulic fracturing and the horizon wells development (Wang et al., 2014). The mechanical properties of the shale both affect the fracture propagation and the stability of the wells. However, the traditional uniaxial compressive strength (UCS) is highly dependent on the integrity of the shale. The UCS is a destructive test with poor repeatability, which reduces the core’s utilization value. Besides, the accuracy of cm-above cannot test the mechanical properties of organic matter (OM). For commercial development, the horizontal wells must pass via high total organic carbon (TOC) formation. The properties of OM deserve more attention, though they are difficult to determine.

Scanning electron microscope (SEM), energy dispersive spectrometer (EDS), nanoindentation, and atom force microscope (AFM) have been used to measure the micro properties of the shale(Wang et al., 2018). Cheng et al. (Cheng et al., 2021) classified bedding layers of the shale into fine-grained, transition and coarse-grained layers by SEM and the mechanical properties of each layer are tested by nanoindentation. Kumar et al. (Kumar et al., 2012) located the kerogen by focused ion beam and the whole kerogen was tested by one nanoindentation point. Xu et al. (Xu et al., 2020) first reported the friction behavior of the kerogen by AFM. Eliyahu et al. (Eliyahu et al., 2015) found the stiffer kerogen surround the softer bituminous by PeakForce quantitative nano-mechanical mapping (PK-QNM) AFM mode. The shapes of OM in marine and continental shales are rather different (Tian et al., 2018). However, currently, studies are focused on the properties of circular bulk OM. The properties of long-strip OM are rare to report.
Experimental Investigation of Hydraulic Fracture Growth in an Anisotropic Rock with Pre-Existing Discontinuities Under Different Propagation Regimes
Authors: Lu G. , Momeni S. , Lecampion B.
Published: September 2022

Laboratory experiments have been carried out to investigate the growth of hydraulic fracture (HF) in an anisotropic rock with pre-existing discontinuities such as bedding planes and veins. The experiments are designed in light of scaling relationships that enable investigation on the impact by the weak mechanical discontinuities on the HF growth under desired regimes (under either a toughness dominated or a lag-viscosity dominated regime based on the scaling analysis). According to our laboratory observations, planar HF growth is promoted in the experiments under the lag-viscosity regime, in which the radial HF is able to cross both the bedding planes and veins. In contrast, profound influence of the weak discontinuities is shown in the toughness dominated experiments, causing the HF to be diverted into, or arrested by the pre-existing weak planes. The test results suggest that the complexity of the fracture path is highly dependent on a dimensionless toughness, Km. This laboratory study highlights the importance of the hydromechanical characteristics in the HF propagation in anisotropic rocks with pre-existing weak discontinuities.

1 INTRODUCTION

Weak discontinuities, such as weakly cemented bedding planes, veins, natural fractures, and defects are often encountered in unconventional reservoirs. It has been shown by both laboratory (Suarez-Rivera et al., 2013; Burghardt et al., 2015; Lee et al., 2015; Llanos et al., 2017; Fu et al., 2018; Xing et al., 2018; Lu et al., 2021) and field-scale hydraulic fracturing experiments (Warpinski and Teufel, 1987) that the discontinuities can locally reduce the strength of the rock, and alter the propagation direction of a hydraulic fracture (HF) that is growing towards the planes formed by the discontinuities. Such interaction between the HF and discontinuities can lead to the HF crossing, diverted into, or completely arrested by the pre-existing weak planes.
Numerical Simulation of Limited-Entry Fracturing in Multi-Layer Heterogeneous Reservoir
Authors: Wang F. , Deng J. G. , Liu W. , Tan Q. , Tan Y. W.
Published: September 2022

Limited-Entry fracturing underwrites commercial production from multi-layer heterogeneous reservoirs. The uneven contribution of multi-layer can be adjusted by Limited-Entry Fracturing to improve the productivity of poor formations and better control the propagation of fractures at each cluster position. In this study, the fracture propagation model is combined with reservoir productivity simulation to explore the effect of perforation parameters on multi-layer fracture propagation and enhanced oil recovery in multi-layer heterogeneous reservoirs. The fracture propagation model considers the impacts of perforation parameters and reservoir properties on hydraulic fracture morphology, which provides a theoretical basis for completion optimization in limited-entry fracturing. This work also emphasizes the control of fluid partition at each cluster. Based on the geomechanical model of the PengLai oilfield, the reservoir productivity was simulated after limited entry fracturing treatment. In addition, the multiple cluster fracture morphology is analyzed to assess the performance of adjusting perforating parameters in overcoming rock heterogeneity. Numerical simulation results show that the application of adjusting perforating parameters is beneficial to multi-layer recovery balance. The fracture length and width build with the increase of perforation density, diameter, and decrease with permeability and minimum horizontal principal stress. Moreover, the effect of limiting entry fracturing is obvious, increasing cumulative oil production by 10%~20%. This paper provides good guidance for perforation parameters optimization for limited-entry fracturing in multi-layer heterogeneous reservoirs.

1. INTRODUCTION

Miller evaluated 114 wells in six U.S. shale basins (Marcellus, Haynesville, Eagal Ford, Fayetteville, Barnett, and Woodford), and found that the proportion of invalid perforation clusters was about 30%. Reservoir heterogeneity and completion quality are the key factors affecting the production of each cluster. There are few invalid perforation clusters using 2~6 cluster perforation schemes.

Ugueto et al. used optical fiber temperature and acoustic monitoring technology to analyze the fracturing of multi-cluster fractures and found that effective liquid inlet clusters accounted for 50 % ~ 70 % of the total perforation clusters. He proposed that maintaining high perforation friction is the key factor to increase the number of effective perforation clusters.
Evaluating the Influence of Parameter Inputs on Macroscopic Behavior of Bonded Block Models with Inelastic Blocks
Authors: West I. , Walton G.
Published: September 2022

Bonded Block Models (BBMs) are commonly used to simulate laboratory Unconfined Compressive Strength (UCS) and triaxial tests on rock. BBMs require input parameters that describe the deformation of the blocks themselves (block properties), as well as the interaction of the blocks with adjacent blocks (contact properties). The blocks that make up BBMs can be modeled either elastically or inelastically, where elastic blocks only deform elastically, whereas inelastic blocks both deform elastically and can yield. BBMs with inelastic blocks are unique in that they are capable of simulating the deformation and breakage of mineral grains, allowing them to simulate a broader range of rock behaviors. Previous studies have documented the effects of variation of contact properties and elastic block properties on the overall behavior of BBMs, but little has been written regarding the effects of inelastic block properties. This study evaluated more than 300 sets of inelastic block input parameters to identify their influences on trends in BBM macroscopic behavior. The inelastic block properties were found to only affect the peak strength and the post-peak behavior (like brittleness) of the BBM, within the range of values tested.

1. INTRODUCTION

Mechanical behavior of rock has historically been characterized in the laboratory via Unconfined Compressive Strength (UCS) and triaxial tests (Robertson, 1955; Handin and Hager, 1957). With the continued advances in computing, however, numerical models have become increasingly used to study rock behavior. Numerical models can be used to complement laboratory testing, as they require significantly less time and labor to complete. Specifically, the behavior of low porosity intact rock in the context of UCS and triaxial tests can be simulated using Bonded Block Models (BBMs) (Ghazvinian et al., 2014; Farahmand and Diederichs, 2015; Sinha and Walton, 2020).

BBMs are a subset of discrete element method (DEM) modeling where material is represented as a series of continuous elements that interact discretely with adjacent elements. The deformations of these continuous elements, and their interaction with adjacent elements, are governed by a series of input parameters (Jing, 2003). Each input parameter affects the DEM model’s macroscopic behavior uniquely. In cases where numerical models use input parameters that cannot be directly tested or estimated from field or laboratory testing, as in the case of BBMs, the macroscopic behavior of the model must be calibrated to laboratory data via an iterative process of varying the input parameters.