bluuebunny/crossref_metadata_2025 huggingface dataset:
Hydraulic Crack Propagation and Rock Permeability Under Osmotic Pressure Gradients with Implications for Deep CO2 Sequestration and Fraccing
Authors: Bažant Zdenek P. , Nguyen Anh Tay , Xu Houlin , Asem Pouyan , Labuz Joseph F.
Published: August 2024

Long-term deep sequestration of CO2-rich brine in deep formations of ultramafic rock (e.g. Oman serpentinized harzburgite) will be feasible only if a network of hydraulic cracks could be produced and made to grow for years and decades. Fraccing of gas- or oil-bearing shales has a similar objective. The following points are planned to be made in the presentation in Golden. 1) A branching of fracture can be analyzed only if the fracture is modeled by a band with triaxial tensorial damage, for which the new smooth Lagrangian crack band model is effective. 2) To achieve a progressive growth of the fracture network one will need to manipulate the osmotic pressure gradients by changing alkali metal ion concentration in pore fluid. 3) A standardized experimental framework to measure rock permeability at various ion concentrations and various osmotic pressure gradients is needed, and will be presented.

1 INTRODUCTION

Carbon dioxide (CO2) emissions by human activities is the largest contributor to global warming; therefore, effective carbon sequestration technologies attract great amount of interest. One emerging and promising technology for storing CO2 in the subsurface permanently is through carbon mineralization in mafic and ultramafic rock (Kelemen and Matter, 2008). Despite the abundance of these types of rock in the Earth's upper crust (Matter et al., 2016), the rate of this process in nature is too slow to reduce CO2 emissions effectively (Seifritz, 1990). One of the key challenges to achieve a sustainable and large-scale storage of CO2 by mineralization is to engineer a progressive growth of a fracture network conveying water with dissolved CO2 to reach a gradually increasing volume of the mafic rock formation. The CO2 rich water often cannot penetrate the tight matrix of silica-rich serpentinized harzburgites because under high concentrations of CO2, the wetting angle of CO2 -bearing water-rock-rock interface exceeds the critical value of 60 degrees. Therefore, the presence of a family of cracks is the only means by which CO2 -bearing fluids can interact with matrix of ultramafic rock (Bruce Watson and Brenan, 1987). Lateral fracture branching from a major fracture provides a sustainable fluid pathway and therefore is essential for continued rock-water geochemical reactions that lead to mineralization of carbonate minerals. Realistic computational modeling of hydraulic fractures in peridotite or basalt must involve lateral fracture branching and account for stress distribution changes between solid and fluid phases under constant tectonic stress, triggered by pore exposure to fluid pressure in hydraulic cracks.
Evolution of the Reservoir Stress Path During Depletion and Re-Inflation and its Implications
Authors: Seth P. , Mikulencak D. , Hofmann R. , Dudley J. W.
Published: August 2024

Several researchers have studied the impact of reservoir depletion on rock mechanical behavior and associated changes in in-situ stresses and reservoir depletion stress path. However, the evolution of the reservoir stress path (ratio of change in minimum horizontal stress with reservoir pressure change) due to re-inflation of the reservoir during injection operations such as waterflooding is less understood.

In this work, a more fundamental approach to the evolution of the reservoir stress path under both depletion and re-inflation is studied through core plug uniaxial-strain experiments and field-scale numerical modeling which includes the impact of plastic deformation. Both unconsolidated and consolidated sandstones are considered. Results from the uniaxial-strain compaction experiments agree with findings from 3-D field scale numerical modeling that the injection stress path coefficient γh,i = Δσh/ΔPinj is either similar or greater than the depletion stress path coefficient γh,d = Δσh/ΔPdep.

The findings in this study have significant implications for waterflooding operations, infill drilling window estimation for re-inflated reservoirs, and CO2 capture and storage operations (CCS). The assumptions on γh,i directly impact the allowable injection pressure, injection rate, and storage capacity for CCS projects. Hence a more thorough understanding could prevent overly conservative designs and promote a more accurate screening of potential waterflooding, infill drilling, and CCS projects.

1. INTRODUCTION

The reservoir minimum horizontal stress path is the ratio of change in total minimum horizontal stress, Δσh to change in reservoir pressure, ΔP:

(equation)

It is crucial to understand the anticipated minimum horizontal stress changes in a reservoir during long-term production and during injection operations such as waterflooding because σh is closely related to hydraulic fracturing in a normal stress environment. When describing the reduction in σh from depletion, the stress path coefficient is defined as γh,d. When describing the increase in σh from re-inflation, the stress path coefficient is defined as γh,i. The Δ's in these definitions are defined to always give positive values of γh,d or γh,i. The assumptions on γh,i (injection stress path coefficient) could impact the allowable injection pressure, injection rate, and storage capacity for waterflooding & CCS projects and a more thorough understanding could prevent overly conservative designs.
Definition Please – A Rock Engineering Dictionary
Authors: Yang B. , Li Y. , Ambah E. , Elmo D.
Published: August 2024

definition /def-i-ni-tion/ noun a statement of the meaning of a word, commonly found in a dictionary. Every discipline has its own language – domain specific terminology that allows practitioners to better understand the problem and communicate with one another. While some words and phrases are only found in one specific discipline, there are others that are found in a variety of related disciplines and subdisciplines. Examples in disciplines related and/or adjacent to rock engineering include the terms validation (which has differing definitions in machine learning compared to numerical modelling) and fines (which has differing definitions in soil mechanics compared to cave mining). Confusion may arise when these terms with differing discipline definitions are not defined in their specific context in the literature. Adding to this confusion is the misuse of certain terms in rock engineering, such as accuracy, precision, and quantifying. The goal of this paper is to clarify the definitions of rock engineering terms that are found in other related disciplines, as well as clarify the definitions of rock engineering specific terms. By providing this dictionary of rock engineering terms, we hope to standardize rock engineering vocabulary, allowing for clearer communication among practitioners and students.

1. INTRODUCTION

For any rock engineers who competed in spelling bees in their childhood, the phrase "definition please" may ring a bell. During spelling bees, contestants are able to ask for the definition of a word ("definition please?") to help them spell it. While spelling bees are no longer an aspect of our lives after elementary school, asking for the definition of a word remains an important aspect of research and professional development. Every discipline has its own language – domain specific terminology that allows practitioners to understand the problem in greater detail and to better communicate with one another. Rock engineering language consists of its own terminology (such as rock mass rating or geological strength index) and terminology overlapping with other disciplines, such as with soil mechanics, statistics, and numerical modelling. Confusion may arise when terms are not defined in their specific context, especially those overlapping with other disciplines. This confusion is further exacerbated by the tendency of rock engineers to both misuse certain terminology (such as accuracy, precision, and quantity) and use others interchangeably when they do not have the same definition (such as imbalanced data/skewed data and calibration/validation). As a result, there is a clear need to clarify the definitions of certain rock engineering terms.
Hyperparameter Tuning of an Artificial Neural Network (ANN) for Laboratory Acoustic Emission Source Location
Authors: Xiong Q. , Johnson E. K. , Wu C. S. , Hampton J. C.
Published: August 2024

Acoustic emission (AE) testing, a technique that has been extensively applied in experimental rock mechanics, traditionally requires source location analysis with both pre-processing and post-processing steps. Performing real-time decision-making that relies on in-situ rock fracture information is hindered by this primarily post-testing analysis technique. This paper examines the potential for using an artificial neural network to replicate the algorithm and output near instantaneous raw source locations; through hyperparameter tuning, this raw output can be improved to approach the accuracy of the standard algorithm. On-disk waveform features are extracted by a trained convolutional neural network (CNN) signal processing model and passed to the ANN through an interlayer. This architecture not only provides the potential for parallel processing but also the ability to directly "read out" raw source locations from the on-disk data. The results of this model provide promising source location predictions despite being only a conceptual example of an ANN for this problem. A further developed model may contain a trained CNN for extracting important waveform features; however, this topic exceeds the scope of this paper and will be the theme of future work.

1. INTRODUCTION

Acoustic emission (AE) testing has been extensively used for delineating the rock fracture process in a variety of scientific and engineering applications [1-6]. This technique uses piezoelectric AE sensors to detect energy releases from rock fractures. Arrival times of AE signals and sensor coordinates can be passed to an optimization function, based on the time delay of wave propagation, for locating the source of an energy release. Procedures within laboratory AE source location analysis, in general, include steps of pre-processing, source location, and post-processing as depicted in Fig. 1. Such procedures have been well-established and practiced for decades. During pre-processing, signals are recorded onto the disk and the signal processing codes are applied to the recorded signals for extracting the arrival times and other features. The results of pre-processing (i.e. the arrival times of AE signals) are then fed into a source location algorithm. This algorithm first produces raw results of source locations and then refines them by filtering out disqualified locations based on the physical principle [7] or mathematical (i.e., error or residual) feature [8]. After completing the previous two steps, source locations can be further used for visualizing the rock fracture propagation path, source type classification [6, 9-11], clustering/declustering analysis [12, 13], and other advanced analysis [14-17].
Kick Warning and Pressure Inversion Method Based on Wellhead Pressure Signal
Authors: Duan Shiming , Song Xianzhi , Yao Xuezhe , Xu Zhengming , Zhou Mengmeng , Zhu Zhaopeng , Cui Yueqi
Published: August 2024

Kick detection seriously restricts safe and efficient drilling, so accurate and timely warning and analysis are very important. This paper is based on drilling data and optimizes parameters of wavelet analysis such as mother wavelet function, data frequency, and data length. Using the wavelet analysis method, the wellhead pressure signal undergoes decomposition. The obtained signals are combined with logic rules to constrain the intelligent kick warning model, and the final model accuracy reaches 90.08%. To further analyze the kick parameters, spectral analysis is used to quantitatively extract the wellhead kick pressure fluctuations which is used to set the wellhead boundary. By integrating perturbation theory with the governing equation, an analytical solution for pressure propagation and attenuation in the liquid phase is proposed. This analytical solution is applied to the flow model, enabling real-time solutions and analyses of bottom-hole kick fluctuation pressure and volume. The final model demonstrates a relative error of 0.4%. This model is expected to provide new methods for the detection and control of kick.

1. INTRODUCTION

Drilling is the only way to create oil and gas channels, and the process is complex and changeable. Due to factors such as inaccurate formation information prediction and improper operations, drilling risks such as the kick, lost circulation, and blowout can easily occur (Vandenbussche et al., 2012). Among them, kick is one of the common drilling risks. The fundamental reason for the kick is that the bottom hole pressure is lower than the formation pressure during the drilling process. Then the formation fluid invades the wellbore, causing the volume of fluid in the wellbore to instantly increase and kick from the wellhead. When a kick occurs, if it is not detected in time or dealt with too late, it is likely to induce a blowout accident(Aime et al., 1967; Han et al., 2017). In addition, when there is gas in the invading fluid, the bottom hole gas continues to rise with the drilling fluid, the pressure and temperature decrease, and the gas expansion accelerates. As a result, the closer to the wellhead, the greater the drilling fluid flow rate, and the more difficult it is to control the wellbore pressure (Alhuthali et al., 2010). For example, the "12.23" blowout accident in Kaixian, Chongqing, China(2003), and the blowout in the Gulf of Mexico in the United States(2010), both caused serious consequences such as equipment damage, casualties, environmental pollution, and scrapping of oil wells (Rathnayaka et al., 2012). Therefore, kick has become one of the recognized high-frequency and high-risk accidents in the drilling industry (Fu et al., 2015). Rapidly detecting kick signals and analyzing the kick process are important means to help quickly deal with kick risks.
Assessment of Thermal Effects on the Formation Breakdown Gradient in APB Mitigation Scenarios
Authors: Souza B. S. P. , Souza C. O. , Fontoura S. A. B.
Published: August 2024

This work aims to investigate the influence of temperature variation on the formation breakdown gradient in scenarios of annular pressure build-up (APB) mitigation during well production. In subsea well projects, it is common to mitigate the effect of APB through the open shoe method, which involves allowing formation fracture below the casing shoe. In this analysis, the fracture gradiente obtained through leak-off tests conducted in the field is typically used. However, the breakdown pressure tends to be higher than the fracture gradient and can be further augmented by temperature increase, potentially resulting in undersizing of well structure elements and eventual integrity failure. To assess the potential implications in well design, a 1D geomechanical model was developed, and thermo-hydraulic simulations were conducted for two wells located in the Brazilian coast. Then, the breakdown gradient calculations were performed, considering variations in pressure and temperature in the confined annuli, primarily comprising shale layers. As a result, variations of up to approximately 19% were observed in the breakdown gradient. Significant reductions in the casing safety factors were observed for the analyzed wells, approximately 37% reduction in the burst safety factor and 25% in the triaxial safety factor.

1. INTRODUCTION

The Theory of Thermo-Poro-elasticity has been widely discussed and presented in various wellbore stability and reservoir stimulation works. The stress concentration around the borehole is strongly affected by temperature. In scenarios of narrow drilling windows, for instance, cooling induced by fluid circulation can lead to losses to the formation due to the reduction in stress concentration, and consequently, the breakdown pressure (as well as the collapse pressure). Conversely, heating tends to increase the breakdown pressure. Rizvi et al. (2022) presented some case studies where the bottom hole temperature was affected by operational drilling parameters variation leading to fluid loss. The same effect is described in many others works (Maury and Idelovici, 2015, Li et al, 1998, Liu and Zhu, 2018, Tao and Ghassemi, 2010). As a point of view from reservoir stimulation, Azevedo et al. (2023) demonstrated that the minor in situ horizontal stress can be reduced by cooling of the rock during cold fluid injection through numerical analysis and evidence of field cases.
High Temperature Triaxial Direct-Shear Testing for FORGE and Field Scale Implications
Authors: Frash L. P. , Iyare U. C. , K C B. , Meng M. , Smith M. , Kroll K.
Published: August 2024

Rock fractures are the most important element of Enhanced Geothermal Systems (EGS) but we lack the necessary data to predict the combined effect of temperature, flow, mechanics, and chemistry on the forecasted effectiveness of these fractures for heat extraction and power production. Here, we seek to quantify the strength, deformation, and hydraulic conductivity of rock fractures before and after shear slip, at geothermal reservoir conditions. This information enables evaluation of the likelihood that hydraulically induced shear slip will improve the performance of EGS. This data can also aid risk forecasting for injection induced seismicity. Concurrent effluent analysis yields insights regarding the chemical reactivity of fresh shear fractures. Our measurements were obtained using triaxial direct-shear experiments conducted at conditions replicating well 16A(78)-32 at the Frontier Observatory for Research in Geothermal Energy (FORGE) in Milford, Utah. We also implement these measurements into reservoir models to evaluate their impact on predicted reservoir performance relative to prior estimates.

1. INTRODUCTION

Geothermal energy retains promise to supply clean stable electrical power and heat (Hamm et al., 2018), as well as flexible power to accommodate the intermittency of wind and solar energy (Ricks et al., 2024). Predicting the behavior of rock fractures is key to expansion, especially for Enhanced Geothermal Systems (EGS) because of its requirement for fractures to facilitate fluid flow and heat extraction (Tester et al., 2006; Brown et al., 2012). However, the properties of fractures at hot and deep conditions are not well known, especially if the effects from stimulation, chemistry, and mechanics are to be considered. The Frontier Observatory for Research in Geothermal Energy (FORGE) is an opportunity to better understand such processes by comprehensive scientific assessment of a hot dry rock (HDR) geothermal resource (Podgorney et al., 2023), along with the performance of technologies needed to access and harvest the heat.

Here, we present laboratory experiments to characterize thermal, hydraulic, mechanical, and chemical (THMC) coupled processes related to the stimulation of and flow of fluid through shear-induced fractures. Results from this work reveal insights into the potential of hydraulic shear stimulation to enhance flow and quantify key properties for fractures, including strength, frictional properties, dilation tendencies, and chemical reactivity; the details of which are included herein.
A Conceptual Subsurface Risk Management and Measurement, Monitoring and Verification Design for an Offshore Carbon Capture and Storage Site in Japan
Authors: Nii K. , Nakayama S. , Ohira A. , Ashida T. , Qiu K. , Lee H. , Wada N. , Yamabe H.
Published: August 2024

This paper presents a case study on the conceptual subsurface risk management and measurement, monitoring, and verification (MMV) design for an offshore CCS carbon capture and storage (CCS) site in Japan. Based on the available geological and carbon dioxide (CO2) numerical simulation results, preliminary risk assessment and risk management analyses were conducted for this site. This risk management analysis identified the key monitoring tasks of MMV. The MMV design was subsequently conducted to develop a site-specific and risk-based MMV plan to proactively address the potential subsurface risks for the given site. The paper describes the workflow of conceptual subsurface risk management and MMV design, summarizes the key considerations and findings, and sets examples for conducting similar evaluations for other CCS projects.

1. INTRODUCTION

The Government of Japan announced the goal of achieving carbon neutrality by 2050, and carbon capture and storage (CCS) is considered a critical part of the overall solution to achieve the goal. In 2023, seven potential offshore CCS projects were selected by the government as the first initiative for the CO2 storage feasibility study toward the commencement of commercial CCS operations by 2030.

Subsurface risk management and related MMV design are critical parts of the feasibility study, as the success of a CCS project relies on the long-term containment of the injected CO2 in the storage complex.

In this context, conceptual subsurface risk management and MMV design were conducted at one of the candidate sites located offshore Japan by leveraging the enriched knowledge of worldwide CCS guidelines and regulations on CCS subsurface risk management and MMV planning.

2. INTRODUCTION OF THE STORAGE SITE

The offshore carbon storage site, located around the Tokyo metropolitan area, was selected by INPEX for potential CCS operations. CO2 will be transported by onshore and offshore pipelines from emitters located in the metropolitan area. The injection operation is planned to start in 2030 and continue for more than 30 years, with a target injection rate of approximately 1.0 million tonnes per annum (Mtpa). Considering the water depth around the potential CCS site, the platform injection concept was selected. The target storage aquifer in the site employs a continuous and thick, deep- and shallow-water marine sedimentary succession.
Development of Hydraulic Fracturing Evaluation Techniques Using Chemical Adsorption Mechanics
Authors: Zhang Shang , Zheng Danzhu , Yu Mengjiao
Published: August 2024

In order to identify problems during the fracturing job and optimize the hydraulic fracturing design for future development, an effective method for monitoring and evaluating the hydraulic fracturing operation is needed. Due to the complex nature of the process, most of the existing techniques for hydraulic fracturing diagnostics and evaluation are limited.

In this research, a direct far-field measurement method was also developed in this research by utilizing chemical adsorption mechanics. A specially designed surfactant was tested in laboratory experiments for its ability to adsorb on the fracture surfaces. The advantage of this method is it can bypass the difficulties of assuming the fracture geometry and directly translate the fracture surface area into stimulated reservoir volume (SRV). It will be especially useful in naturally fractured reservoirs, where the hydraulic fracture will interact with the existing natural fractures. A dynamic adsorption model was developed for the proposed evaluation method in field scale.

Furthermore, a hydraulic fracturing efficiency improvement method was proposed using the same surfactant. An economic analysis was conducted using the comprehensive hydraulic fracturing model developed in this research. The results showed that the efficiency of hydraulic fracturing could be significantly improved using surfactant adsorption.

1. INTRODUCTION

Hydraulic fracturing is a process that could improve the recovery of hydrocarbons from formations, especially for low permeability formations. A successful hydraulic fracturing operation is the key to enabling economic production from low permeability reservoirs. Because of lacking affordable data acquisition technologies during the operation, it has been a "black-box" tool for the industry for decades, although many researchers have tried to measure or numerically describe the hydraulic fracturing process (Warpinski et al., 1994; Cipolla & Wright, 2000).

One of the reasons for this situation is the difficulty of verification. The actual fracture geometry that is located at extreme in-situ conditions thousands of feet under the surface is nearly impossible to obtain directly. Another reason is that the whole process is extremely complex. A poorly designed operation or problems during the fracturing job, such as inadequate fluid volumes, inappropriate proppant selection, and insufficient treatment stages, would result in a less efficient fracture network, contributing to the flow in the production phase (Sinha & Ramakrishnan, 2011). If no proper evaluation techniques were deployed during the fracturing operation, operators could not realize the underperformance of the well until it had been put into production for a while. Since then, a workover or re-fracturing job has been needed to optimize production, which would cause a considerable amount of extra cost and an enormous amount of non-productive time (NPT).
Effect of the Stress Regime on Injection-Induced Seismicity
Authors: Xiao Y. , Haitao Y.
Published: August 2024

The distribution of local stress regime has a significant influence on natural earthquakes, while its role in controlling injection-induced fault reactivation and associated seismicity remains poorly understood. This paper investigates the relationship between fault aseismic slip, seismic slip and seismicity magnitude under different stress regime. Results show that the seismic slip zone will exceed the pressurized area with the increase of initial slip tendency under the strike-slip-faulting stress regime. Compared with fluid pressure, the seismic slip is mainly determined by a sudden increase of the shear stress at the aseismic slip zone boundary. In addition, the location of the microseismic events moves towards the fluid pressure propagation front. The larger slip area and seismicity magnitude are easier to be induced under strike-slip-faulting stress regime than thrust-faulting stress regime. The tensile failure and higher permeability of the fault induced at injection phase for normal-faulting stress regime leads to a greater seismogenic hazard at the shut-in stage.

1 INTRODUCTION

In recent years, induced seismicity events have been increased rapidly due to the injection of large volume fluid into reservoir formations (Rutqvist et al., 2015; Ellsworth, 2013). These earthquakes are triggered by reactivating critically stressed faults. The fault reactivation process is highly dependent on the stress regime, the pore pressure, the hydrological properties of the fault and surrounding rock. The range of geological reservoirs may reached up to several kilometers and the in-situ stress and fault geometry experience obvious variation. A large number of geophysical observations have shown that the regional reservoir stress is a key control factor for fault slip behaviour (Sheikholeslami et al., 2021). The magnitude and frequency of the natural earthquakes have a strong relationship with stress regime (Scholz, 2015). It is postulated by Amini and Eberhardt (2019) that a critical fault in strike-slip fault stress regime respond differently than that in a normal or thrust fault stress regime. However, the effect of stress regime on spatiotemporal evolution of injection-induced fault reactivation and seismicity is still not clear.
Calibration of Rockmass Failure Criteria for Mines Using Seismic Monitoring Data
Authors: Malovichko D. A. , Rigby A.
Published: August 2024

A method is proposed for the calibration of a mine-scale numerical stress models using seismic monitoring data. The method is based on comparing the gridded observed and modelled seismic potency of slip-type seismic events according to a misfit/cost function. Expressions are derived for the gradients of this misfit function with respect to the parameters of Mohr-Coulomb failure criteria defining the intact and post-peak behaviour of the rockmass. Determining these gradients requires a single modelling simulation regardless of the number of model parameters; this affords a significant reduction in runtime compared to a simple finite-difference approximation, which requires a number of simulations equal to twice the number of model parameters. The gradient of the misfit function is used in an optimization algorithm (nonlinear conjugate gradient method) to update the failure criteria. The performance of the optimization is demonstrated using synthetic and real data. The proposed method makes it possible to promptly reconcile the numerical model of mines with recent seismic data, which is important for operational forecast of seismic and ground motion hazards for planned mining. An example of the effect of updating the stress model to the assessment of ground motion hazard is presented.

1 INTRODUCTION

Numerical stress models are used extensively in mine engineering practice. The models make it possible to assess the deformations and stresses in the rockmass, which have been disturbed by excavations (shafts, tunnels, stopes, caves, etc.). This helps to ensure that planned design of the excavations is safe. Modern numerical stress modelling algorithms are powerful. They can describe complex 3D geometry of mining and geology with high resolutions. Various constitutive relations are available to represent the behavior of the rockmass before and after the failure. One of the main challenges in modelling is the reliability and completeness of input information about rockmass properties. For example, the properties of rocks can be assessed for small samples (few centimeters size) extracted from boreholes and these need to be extrapolated to larger volumes (meters and tens of meters). Some parts of the rockmass may have sparse coverage by exploration drilling and, therefore, knowledge of their properties is approximate.
Evaluation of Mechanical Properties of Heavy Oil Injection and Production Pipelines in Multi-Component Thermal Fluid Corrosive Environment
Authors: Weng Jintao , Tian Shouceng , Tian Kangjian , Wang Tianyu , Tan Yawen , Zhang Wenhong
Published: August 2024

Aiming at the problem of dynamic changes in mechanical properties of oil pipes (N80 steel), casings (J55, TP90H, P110 steel) and surface gathering and transportation pipelines (20#) in the multi-component thermal fluid corrosion environment during the thermal recovery of heavy oil. Based on high-temperature and high-pressure corrosion experiments and tensile experiments, this article analyzes the mechanical properties of five types of steels containing corrosion damage. The experimental results show that all five types of steel are severely corroded in this environment, Among them, P110 steel and TP90H steel have the highest corrosion rates, which are 7.83mm/a and 5.78mm/a respectively. Combining the scanning results of SEM, EDS and XRD, it was found that the corrosion products are mainly composed of FeCO3, Fe2O3, Fe3O4 and FeOOH, and these iron oxides formed a double-layer film structure on the steel surface, the outer film is loose and porous, and the inner film is relatively dense. Due to differences in the corrosion products of the inner and outer film layers, there are obvious corrosion pits at the clamp end of the corroded specimens. Tensile tests revealed that the yield strength and tensile strength of steel decrease as corrosion damage increases.

1. INTRODUCTION

Heavy oil resources are abundant and have significant reserves, and are currently a hot spot for oil and gas exploration and development, both domestically and internationally(Omoregbe & Hart, 2022; Yao et al., 2023) Multi-component thermal fluid thermal recovery technology is a highly efficient method for the recovery of heavy oil. This is achieved by injecting high-temperature and high-pressure thermal fluids, such as steam, hot water, N2, and CO2, which reduce viscosity and aid in the recovery process. N2 is not easily soluble in water and has good compressibility. It also has a high volume expansion coefficient and a certain lifting effect on the fluid. On the other hand, CO2 gas dissolves and reduces viscosity when in contact with heavy oil, which can improve the extraction effect and reduce the interfacial tension of crude oil, ultimately improving its fluidity (Dong et al., 2015).
The Influence of Burial History and Capillary Suction on Geomechanical Properties of Clay Shales
Authors: Winhausen L. , Gaus G. , Jalali M. , Amann F.
Published: August 2024

Geomechanical properties of clay shales significantly depend on mineralogical composition, saturation, and burial history. In this contribution, we provide insights into a unique opportunity to study the influence of burial history on geomechanical parameters of a rock unit in a distinctive area in Northern Germany where clay shales were retrieved at shallow depths. In this area, the mineralogical composition is relatively homogeneous, but thermal maturity increases substantially over a lateral distance of approximately 50 km. Using an empirical correlation between vitrinite reflectance and temperature, and assuming a geothermal gradient of 30 °C/km, initial estimates suggest that maximum burial depths range between 1300 m and 3600 m.

Systematic uniaxial compression tests and consolidated undrained triaxial tests under well-defined saturation conditions suggest a major impact of thermal maturity on geomechanical properties. Although peak strength and stiffness are functions of porosity, which is the main parameter influenced by maximum burial, the general hydro-mechanical behavior remains similar. While comparing the first results from two degrees of thermal maturity in this contribution, the overall goal of this systematic analysis is to develop functions that allow predicting geomechanical properties for a clay shale formation that has undergone different burial histories.

1 INTRODUCTION

Shales and similar clay-rich rocks have increasingly attracted attention for utilization as host rocks for the final disposal of radioactive waste in deep repositories. A precise characterization of such rocks in terms of their (thermo-)hydro-mechanical behavior is therefore fundamental for evaluating their suitability as a geological barrier. This task is, however, challenging since the properties of clay-rich rocks are highly influenced by, for instance, structural and mineralogical heterogeneities. They exhibit state-dependent properties, meaning that mechanical strength or permeability are functions of saturation.

Another important factor influencing the geomechanical properties of shales is their geological burial history, i.e., thermal maturity. During burial, the rock experiences different diagenetic processes such as compaction or cementation as a result of elevated stresses and temperatures.
Prediction of Formation Pressure Relief by Using Neural Network
Authors: Li Yanchao , Gao Yanfang , Shen Shijie , Li Dengke , Chen Zupeng , Liang Xuelin
Published: August 2024

Accurate formation pressure relief prediction is crucial, especially in drilling operations technically and economically. Its prediction will save costs and time, and even the right decisions can be taken before problems occur. The available correlations for pore pressure prediction depend on logging data, formation characteristics, and a combination of logging and drilling parameters. The objective of this work is to apply BP neural networks (BPNN) models to estimate the formation pressure relief through the available drilling data. The used parameters include Gama (Gr), interval transit time (Dt), wave velocity, and resistivity(R10). A data set obtained from some vertical wells was utilized to develop the predictive model. A different set of data was utilized for validating the proposed artificial intelligence (AI) models. The models forecasted the output with a good correlation coefficient (R) for training and testing. Moreover, the mean relative Error (MRE) did not exceed 15.9%. By comparing and analyzing the formation pressure predicted by the traditional model Bowers, the BPNN model has better performance. The predicted results of the BPNN model are closer to the true pressure coefficient and have smaller errors. This study proves the reliability of the proposed models in estimating the formation pressure relief while drilling using drilling data.

1. INTRODUCTION

Pore pressure prediction is very important for drilling operations. Pore pressure influences drilling efficiency and well operation costs, such as well designing, wellbore stability analysis, casing design, mud program designs, drilling operations, and structural optimization (Lee B Y et al., 1998). Accurate pore pressure determination is important for selective production and injection.

The abnormal pressure is divided according to the size of the formation pressure coefficient (SONG Xianzhi et al., 2022), which is defined as the ratio of the measured formation pressure to the hydrostatic pressure at the same depth, which is a dimensionless quantity, which reflects the relative level of the formation pressure (LUO Ming et al., 2021). When the pressure coefficient is less than 0.8, it is abnormal low pressure, and when the pressure coefficient is between 0.8∼1.2, it is normal pressure. When the pressure coefficient is less than 0.8 or greater than 1.2, it is abnormal pressure. The normal pressure of pore pressure usually does not cause any drilling problems. Abnormal pressures need to be considered in the design of oil wells; Tubing, slurry density, cement planning, and casing solidification depth are all included in this. Many problems, such as kicking and bursting, shale uplifting, and differential pressure pipe adhesion, are thought to be the result of pressure abnormalities (Rock Mechanics, 1995).
Experimental Investigation of Chalk Influx in a Depleted Reservoir
Authors: Bhuiyan M. H. , Papamichos E.
Published: August 2024

Chalk is generally a weak reservoir rock with high porosity and moderately low permeability compared to sandstone reservoir rock. Chalk production and chalk influx events are a challenge that operators encounter during the production of hydrocarbons from chalk reservoirs. Appropriate completion of the well is therefore crucial for long term optimal production. The challenges are bigger when producing from a depleted reservoir. To avoid problems during production and increase the lifetime of the producing reservoir, it is crucial to comprehend the behavior of chalk production and/or chalk influx in a depleted reservoir. A series of experiments has been undertaken to investigate this behavior in simulated depleted reservoirs using outcrop Mons chalk as testing material in laboratory experiments. The tests were conducted in two phases. The first phase involved simulation of depletion at two different stress levels followed by re-pressurization and the second phase replicated production by increasing the applied drawdown. The results indicate a reduction in drawdown stress within a depleted reservoir compared to a non-depleted one. It was also found that the critical drawdown is independent of the effective stress amplitude.

1. INTRODUCTION

Weak chalk has a strong tendency to compact when the hydrocarbon is produced due to an increase in effective stresses. The compaction observed in the high porosity chalk reservoir can be extended to the sea floor surface; one well-known example of this phenomenon is the surface subsidence observed in the Ekofisk Field in the North Sea. Oil companies employ several reservoir management systems to prevent such situations. One strategy involves increasing the pore pressure in the reservoir to prevent reservoir compaction and enhance oil recovery. However, the high porosity and compressible nature of the reservoir pose significant challenges (Omdal, 2010). Drilling new wells to produce from such depleted and re-pressurized reservoirs is technically demanding in terms of borehole stability. Production of hydrocarbons from depleted and re-pressurized reservoirs adds another level of complication to an already challenging reservoir management system.

Chalk influx or liquefaction in the form of toothpaste like material involves a significant part of chalk formation near the borehole which eventually fills the well, tubing and destroys the flow (Kristiansen and Meling 1996). It is important to understand the behavior and mechanisms of chalk influx to avoid or effectively manage chalk influx events to ensure uninterrupted production and maximize recovery.
3D Fracture Propagation Simulation of Shale Oil Reservoirs with Bedding Planes and Natural Fractures Development
Authors: Wang H. Y. , Guo T. K. , Chen M. , Zhang B. , Wang J. W.
Published: August 2024

The development of shale oil reservoirs has received extensive attention from countries around the world. Shale oil reservoirs are often distributed with a large number of horizontal bedding planes (BPs) and natural fractures (NFs), the presence of both have a greater impact on the propagation of hydraulic fractures. The continuous-discontinuous element method (CDEM) integrates the advantages of the finite element method and discrete element method, which is very suitable for the numerical simulation of complex fracture propagation in shale oil reservoirs. According to the geological characteristics of shale oil reservoirs in Longdong area of Ordos Basin, a three-dimensional fracture propagation model of double BPs and a three-dimensional mine-scale fracture propagation model considering the BPs and NFs were established based on CDEM, the width and range of the opening of BP under the influence of different factors were analyzed, and the fracture propagation law under different factors was clarified. The results show that (1) With the increase of difference between vertical stress and minimum horizontal stress, the BP opening width and the BP opening range both decreases; With the increase of BP cohesion, the BP opening range is reduced. (2) Increased displacement, increased BP opening width and opening range. As viscosity increases, the maximun BP opening width increases but the BP opening range decreases significantly. (3) Under the combined influence of BPs and NFs, the asymmetry of the two wings of hydraulic fracture is significant at low displacement, while the spread non-uniformity of the two wings decreases at high displacement; when the viscosity is high, the NF opening range is small, and the spread of the two wings is non-uniform. (4) At NF approach angles >60°, hydraulic fractures tend to cross through NF, and NF opening range is small. This study provides theoretical guidance for realizing efficient development of target shale oil reservoirs.

1. INTRODUCTION

At present, conventional oil and gas resources are difficult to meet the increasing energy demand of human beings. The shale oil and gas revolution, represented by breakthroughs in the exploration and development technology of unconventional oil and gas resources, has triggered a major change in the international energy landscape (Feng et al. 2020; Tong et al. 2018; Wang et al. 2016). In 2022, China's shale oil production exceeds 300×104 t, a nearly three-fold increase compared to 2018, strongly contributing to the growth of shale oil production, which is currently an important part of China's oil and gas energy mix.
Exploring Ground Penetrating Radar (GPR) Simulation for Imaging and Determining Electromagnetic Wave Velocity in Volcanogenic Massive Sulfide (VMS) Deposits
Authors: Abbasian L. , Butt S. D.
Published: August 2024

Ground-Penetrating Radar (GPR) simulation plays a pivotal role in geophysical methods, aiding in survey design, understanding physical behaviour, and quantifying responses. This study employs the gprMax software to simulate the propagation of electromagnetic waves through different Volcanogenic Massive Sulfide (VMS) deposits, each with unique electrical properties. The fundamentals of GPR modeling and factors influencing survey design (operating frequency, recording time window, temporal and spatial sampling interval) are outlined. Careful consideration of these parameters is essential for effective GPR surveys. In addition, results from the simulations of EM wave propagation through VMS minerals such as Galena, Bornite, Magnetite, Pyrite, Sphalerite and Hematite, and their host rocks were utilized to calculate wave velocities in each mineral, rendering it possible to determine the location of Boundaries of VMS veins within the host rock using this method. Some deposits with lower electrical conductivities, showed possibility of being imaged successfully using Electromagnetic (EM) methods. In contrast, some other deposits, having higher electrical conductivities, tended to weaken electromagnetic signals, especially within the frequency range used in GPR applications. This study enhances our comprehension of GPR simulation and its possible uses in geophysics, specifically in the characterization of diverse geophysical materials that possess distinct electrical properties.

1 INTRODUCTION

Volcanogenic massive sulfide (VMS) deposits, are key sources of metals like Zn, Cu, Pb, Ag, and Au. Also, there is a substantial proportion of pyrite, or iron sulphide (FeS2) that is frequently connected to VMS occurrences. The economic importance of these deposits is underscored by their contribution to metal production. Most VMS deposits consist of massive (>40 percent) sulphide (typically pyrite, pyrrhotite, chalcopyrite, sphalerite, and galena as well as magnetite) (Best, 2015). These minerals and their associated economic minerals are listed in Table 1. GPR simulation is a powerful tool in delineating VMS deposits, crucial for optimizing GPR survey parameters and understanding mineral-host rock interactions. This approach facilitates accurate mapping and exploration of VMS deposits, enhancing the effectiveness of geophysical surveys by allowing for precise adjustments in survey design based on the simulation outcomes.