bluuebunny/crossref_metadata_2025_split huggingface dataset:
Study on the Internal Pressure Strength of Perforated Casing in High Pressure Formation
Authors: Zou Yiqi , Tao Lin , Liu Nanxiang , Gao Deli , Li Wenlong , Chen Xuyue 
Published: September 2023

ABSTRACT
Casing damage is the main form of wellbore integrity failure, severely affecting oil and gas production. The mudstone has rheological properties under the high temperature and pressure of the formation, and creep deformation of the formation leads to increased external pressure of the wellbore. At the same time, perforation operations severely reduce the strength of the casing. Therefore, it is crucial to analyses the collapse strength of perforated casing in mudstone formations. In this paper, a three-dimensional numerical model of the formation-cement sheath-perforated casing is developed for the geological conditions of the Missan oilfield. The casing damage mechanism under long-term rheological effects is revealed. The effects of different casing sizes, casing thickness, perforation diameter and perforation density on casing collapse strength were carried out. The results show that the equivalent force on the perforated casing gradually increases with increasing operating time. For the same parameters, the smaller the casing diameter and the thicker the casing thickness, the higher the residual strength of the perforated casing. The collapse strength of the perforated casing decreases with increasing perforation diameter and perforation density. It is recommended to increase the casing thickness and optimize the perforation parameters in mudstone formations. The study provides a theoretical basis for the field application of perforation technology in mudstone reservoirs and has a good application prospect for improving the casing collapse strength.

INTRODUCTION
The Missan oil field has frequent drilling complications, among which casing damage is a serious problem. The Asmari Formation is 3000m burial depth and has a complex geological structure with extensive mudstone. Field applications and relevant statistics show that the majority of casing damage and failure occurs in the perforation holes. Perforation is an important stage of oil exploration and development, and is closely linked to subsequent production enhancement and reconstruction techniques. During the completion of an oil and gas well, the jet produced by the injection projectile will penetrate the casing, cement sheath and part of the formation. As a result, a number of perforated holes are created in the casing along the injection spiral, resulting in a reduction in the stability of the casing. During subsequent production, the perforated casing is more susceptible to strength failure due to excessive loading, which has a non-negligible impact on the wellbore integrity. At the same time, the creeping behavior of the mudstone at high in-situ stress increases the extrusion of the casing, exacerbating the potential damage to the perforated casing. Therefore, the strength analysis of the perforated casing under mudstone creep is critical to the integrity of the wellbore.
Understanding the Source of Pumps off Gas in Impermeable Rock
Authors: Thorpe D. T. , Chan A. W. , De Gennaro S. , Porter M. J. , Colgan G. , Murray D. 
Published: September 2023

ABSTRACT
While drilling, an increase in background and onset of connection gas is frequently related to an increase in pore pressure within a formation. This can lead to the risk of being near balanced or underbalanced resulting in the possibility of a kick when the pore pressure is greater than the static mud weight. This work shows that in some cases this is unlikely to be the leading interpretation and reacting to the gas by increasing the mud weight can exacerbate the situation. Here, we clearly show that the pumps off gas seen from this well is a result of fault reactivation and not a result of an underbalanced situation. The techniques demonstrated in this report can be applied to other case studies where the cause of pumps off gas is unclear.

INTRODUCTION
The Penguins Cluster is located in the Northern North Sea, 150 km North East of the Shetland Islands (Thorpe, Porter, McKie, & Ritchie, 2020). The cluster is currently going through redevelopment, after the previous host facility reached end of field life in 2021. As part of the redevelopment campaign, the decision was made to build a new Sevan 400 floating, production, storage and offloading vessel and to drill an additional eight wells to supplement the seven remaining production wells. This paper discusses a pumps off gas (POG) response identified while drilling the passive Shetland Group claystone in one of the redevelopment wells.

WELL DESIGN AND STRATIGRAPHIC OVERVIEW
Three of the eight redevelopment wells use a slim well design concept, to help optimise well delivery in terms of both time and cost. The newly applied concept to the Penguins Cluster is a four-string well design, which removes a casing string from the previously carried five-string design. Rather than setting a casing point in the relatively unreactive Heather Formation to case off the reactive Kimmeridge Formation source rock, the design now sets the 9 5/8" production casing in the lower Shetland Group, with the 8 ½" section taking the well to total depth (TD) (Figure 1). The reservoir section must therefore carry a mud weight which maintains the stability of the reactive Kimmeridge Formation, while drilling to well TD.
Simulation of Injection-Induced Slip on a Rate-and-State Fault Considering Poroelastic Effects: A Comparison with Coulomb Failure Stress Criterion
Authors: Xie Qifeng , Wang Lei , Li Qi 
Published: September 2023

ABSTRACT
The Coulomb failure stress (CFS) criterion based on the Mohr-Coulomb friction theory is commonly used to explain physical mechanisms governing injection-induced seismicity. While the CFS criterion can evaluate the onset of fault reactivation caused by fluid perturbations, it cannot tell the kinematic process of fault failure (seismic or aseismic slip). An alternative model for simulating time-dependent earthquake cycles is the rate-and-state friction model, which provides evolving friction depending on slip rate and slip history. To explore the dynamics and stability of fault slip associated with fluid injection, we extend a spring-slider system with a rate-and-state dependent friction law by incorporating the evolving fluid pressure and poroelastic stress. Simulations of continuous constant fluid mass injection rate scenarios using the developed model suggest that injection-induced fault slip behavior is controlled by fault orientation, diffusivity and poroelasticity, and injection rate. Compared to the CFS criterion, our model can offer a temporal component to fault friction and provide new insights on slip, slip rate and trajectory in phase space. We also investigate the relation between cumulative slip displacement versus cumulative injection volume, as well as the event recurrence interval. Our proposed approach has the potential application for evaluating the reactivation of pre-existing faults embedded in the reservoir associated with fluid pressure operations in the field practice.

INTRODUCTION
It has been well established that fluid injection into subsurface reservoirs can induce earthquakes (Healy et al., 1968; Raleigh et al., 1976). One of the most frequently discussed scientific issues is the physical mechanism that causes earthquakes to nucleate in response to fluid injection. The Coulomb failure stress criterion based on the Mohr-Coulomb friction theory is commonly used to explain the mechanism of induced seismicity (Ge & Saar, 2022). The Coulomb failure stress (CFS) and the change in Coulomb failure stress (ΔCFS) can be expressed as
(Equation)
(Equation)
where μ is the friction coefficient that is assumed to be constant above, τ, σn and P refer to shear stress, normal stress (positive for compression), and pore pressure acting on the fault, respectively. Δτ, Δσn and ΔP denote the changes of shear stress, normal stress and pore pressure, respectively.
Statistical Approach to Characterize Stress Field Heterogeneity
Authors: Jimenez Martinez V. A. , Renner J. 
Published: September 2023

ABSTRACT
Stress tensor determination is of importance in many aspects of geothermal energy provision, from the understanding of the propagation orientation of newly created fractures to the control of the pre-dominant stimulation mechanism, hydro-fracturing vs. hydro-shearing. Hydraulic stimulation experiments were carried out in the research mine Reiche Zeche in Freiberg, Germany, in the framework of the STIMTEC and STIMTEC-X projects. Key objectives were to characterize the stress field of the rock volume and evaluate and enhance hydraulic properties. Injection tests were performed in 28 intervals with 0.7 m length enclosed by a double-packer probe, either with pre-existing fractures or initially intact, in 7 boreholes crisscrossing a rock volume of 60×30×30 m3. The data from the injection experiments typically used to determine components of the stress tensor comprise shut-in and jacking pressures, and the orientation of the pressurized fractures. Impression packer testing and acoustic televiewer logging revealed multiple fracture traces for a number of intervals, and thus we face ambiguity regarding the hydraulically relevant fractures. In total, the data set comprises 28 characteristic pressures assumed to correspond to the normal stress on a fracture, but in total 60 fracture traces were detected with a maximum of four fractures in a single interval. The uncertainty in the association of the characteristic pressure with a fracture trace and the fact that a unique stress tensor cannot explain all the observed data, i.e., the stress field is heterogeneous, motivated a Monte Carlo analysis to characterize the stress field in the rock volume. We randomly select subgroups of 5 out of the tested intervals, with one fracture trace randomly selected out of the observed traces for each interval, and then determine the misfit between observed characteristic pressures and the normal stress on the selected fracture trace associated with randomly selected stress parameters. Selecting 5 intervals in principle sufficed to invert the stress field, since we constrained the vertical stress by the known overburden. The total number of combinations of intervals and fracture traces precludes a systematic stress-parameter determination. The Monte Carlo approach allows us to statistically investigate the role of each particular interval and fracture trace for stress magnitude and stress regime.
Assessment of CO2 Injectivity in Highly Deformable Chalk Reservoirs: A Thermo-Hydro-Mechanical Analysis
Authors: Hosseinzadehsadati S. B. , Amour F. , Hajiabadi M. R. , Nick H. M. 
Published: September 2023

ABSTRACT
Depleted hydrocarbon chalk reservoirs are attractive candidates for CO2 storage in Denmark. However, their highly deformable nature presents challenges for CO2 injectivity and storage. This study investigates the potential for thermal effects on reservoir and caprock integrity caused by a 16 year-long supercritical cold CO2 injection in a depleted gas reservoir using a thermo-hydro-mechanical simulation. We focus on quantifying the additional stresses and strains induced by the thermal expansion and contraction of the rocks and examine whether these changes could trigger fracturing/fault reactivation in the chalk and/or the overlaying shale deposits. To address convergence issues in non-isothermal flow modeling, we assume that the density and viscosity of CO2 remain constant with temperature change in the coupled simulation. Our results demonstrate that, with constant rate injection of CO2, temperature propagation is limited to a short distance around the well, and CO2 only cools down the temperature around the injection site. This study provides insights into the feasibility of cold CO2 injection in hot depleted hydrocarbon reservoirs and highlights the importance of considering thermal effects on faults and fractures behavior.

INTRODUCTION
Carbon Capture and Storage (CCS) can help reduce greenhouse gas emissions while transitioning to renewable energy (IPCC, 2005). Depleted oil and gas reservoirs offer significant potential for CO2 storage (Bonto et al., 2021), using natural subsurface storage space that previously contained hydrocarbons for millions of years and reusing existing infrastructure, such as wells, platforms and pipelines (Amour, Hajiabadi, Hosseinzadehsadati, et al., 2022).
Storing CO2 securely underground in depleted oil and gas fields is critical, and the success of this approach depends on ensuring geomechanical stability during CO2 injection, which can have significant implications for cap rock integrity and fault reactivation (Akhurst et al., 2015). Injecting cold CO2 may cause thermal contraction of the reservoir matrix and unload normal compression on existing fractures and faults (Salimzadeh, Paluszny, & Zimmerman, 2018; Vilarrasa & Rutqvist, 2017). This process can lead to an increase in the aperture of impermeable faults and fractures, potentially creating new pathways for CO2 leakage and inducing seismic activity (Min et al., 2005; Rutqvist, 2012). Therefore, the injection of large amounts of low-temperature CO2 into hot, depleted hydrocarbon chalk reservoirs may induce a range of complex and strongly coupled thermal, hydraulic, mechanical, and chemical (THMC) processes (Yin et al., 2011) involving interactions among reservoir formation fluids, CO2, and chalk minerals. As a result, accurately identifying the stresses, pressures, and temperature changes around the injection well is essential to obtaining practical information for injection design, thermal fracturing, and leakage prevention.
Distant Fault Reactivation Due to Temperature and Pressure Changes Accounting for Rock Matrix and Fault Plasticity
Authors: McLean Matthew L. , Espinoza D. Nicolas 
Published: September 2023

ABSTRACT
Large-scale geothermal energy production and carbon geological storage are emerging technologies. Injection of non-native fluids in the subsurface alters reservoir pore pressure and temperature changing the initial state of stress, even beyond the plume and thermal front, which could potentially lead to the reactivation of distant faults. Published work so far usually neglects elastoplastic rock matrix response and effects of plastified reservoir volume on distant stress changes. This paper presents three-dimensional thermo-hydro-mechanical (THM) numerical simulations of (1) a hydrothermal system with injector-producer doublet and (2) a carbon storage site with single injector, both solved with 3D finite element code ParaGeo. First, simulations show that assuming an elastic response for a geothermal reservoir results in more distant stress changes -which can be enough to disturb critically stressed distant faults-, than incorporating a more realistic elastoplastic model for the reservoir rock. Second, injection (without production) of a cold fluid may result in quick distant fault reactivation because the pressure front travels much faster than the temperature front, in the range of a decade or two in our model. Reservoir plasticity plays a negligible role when reservoir pressure increases and effective stress decreases. This work highlights the importance of using a realistic constitutive model and accurate estimation of in-situ stress for evaluating risks on sites subject to heat depletion or fluid injection.

INTRODUCTION
Subsurface activities that alter the pore pressure and temperature are known to potentially result in non-negligible seismicity (Wesson and Nicholson, 1987; Evans et al., 2012; Guglielmi et al., 2015) and may compromise fault sealing capacity if fault offsets become large (Zoback and Gorelick, 2012). Fluid injection increases pore pressure and may reactivate preexisting faults and fractures, triggering microseismic events (Majer et al., 2007). Reservoir cooling changes effective stress and may alter the state of stress well beyond the thermal plume (Kivi et al., 2022). Recent studies suggest that thermo-hydro-mechanical (THM) processes are likely to operate simultaneously but under different spatial extents, intensifying local stress changes and increasing complexity of distant stress changes (Martínez-Garzón et al., 2014). For example, observed seismicity and history matching at the Geysers geothermal field indicates that preexisting fracture reactivation is the result of reservoir cooling and fracture pressure increase with thermal effects dominating seismicity within the thermal plume (Rutqvist et al., 2015).
Experimental Study on Fracture Propagation During Supercritical CO2 Fracturing in Layered Tight Sandstone Reservoirs
Authors: Li S. H. , Xing H. L. , Jin G. D. , Zhang S. C. , Zou Y. S. 
Published: September 2023

ABSTRACT
Supercritical CO2 (Sc-CO2) has a special physical property of ultra-low viscosity (0.02∼0.16 mPa·s) so that it can create branching hydraulic fractures in brittle rocks. However, the major controlling factors of hydraulic fracture propagation during Sc-CO2 fracturing in layered tight sandstones remain unclear. In this study, laboratory fracturing experiments were conducted to systematically investigate the major controlling factors of fracture propagation driven by Sc-CO2. Experimental results show that the samples with lower strength bedding planes tend to form more complex fracture geometry during Sc-CO2 fracturing. Even under a high vertical stress difference of 8 MPa, Sc-CO2 can still open some low strength bedding planes and create multiple hydraulic fractures. With the decrease of horizontal stress difference, the number of fractures formed by Sc-CO2 fracturing in low-strength samples increases. Compared with conventional water-based fracturing, Sc-CO2 fracturing can create multi-branch fractures. In the case of Sc-CO2 fracturing on samples with high strength bedding planes, increasing the injection rate can effectively increase the complexity of fractures. Based on the results of laboratory fracturing experiments, the major controlling factors of fracture propagation during Sc-CO2 fracturing are summarized as bedding plane strength &gt; vertical stress difference &gt; horizontal stress difference &gt; fracturing fluid viscosity &gt; injection rate.

INTRODUCTION
According to the International Energy Agency data, the global CO2 emission in 2019 is about 33.3 billion tons, and its contribution to the worldwide greenhouse effect has exceeded 60%. CO2 capture, utilization, and storage technology (CCUS) is crucial to reduce greenhouse gases effectively. It is the primary technology to realize carbon neutralization for our humanity [1,2]. CO2 fracturing, CO2 displacing, and CO2 huff-puff are valuable technologies for geological carbon neutralization and enhancing oil recovery in the petroleum industry. Since the 1980s, CO2 fracturing has been widely applied to stimulate the oil and gas reservoirs and coal seams characterized by water sensitivity and low formation pressure [3]. In the recent decade, CO2 fracturing has been exploratively applied to the stimulation of shale oil/gas reservoirs [4,5]. Most of the previous CO2 fracturing treatments have achieved a sound effect of increasing oil/gas production. It can be attributed to the advantages of CO2 fracturing, including creating complex hydraulic fractures, reducing formation damage and oil viscosity [6-9]. Moreover, CO2 fracturing can also save water resources and benefit CO2 geological capture [10]. The abovementioned advantages of non-aqueous CO2 fracturing could minimize the drawbacks of water-based fracturing fluids, such as slickwater, x-linked guar, and gel, which are widely used to stimulate unconventional oil/gas reservoirs.
Performance of Geopolymers in Geothermal Wells
Authors: Ogienagbon A. , Korsnes R. I. , Khalifeh M. , Wu Y. , Salehi S. 
Published: September 2023

ABSTRACT
Geothermal wells play an important role in harnessing geothermal energy stored underground as the push for the strategic development of renewable energy increases. The use of conventional wellbore cement in geothermal wells is commonly associated with challenges due to the harsh and highly corrosive environment encountered in geothermal wells. In this study, we numerically evaluated the performance of a granite-based geopolymer based on its mechanical properties under different underground conditions, such as normal (30°C), moderate temperature (90°C), and elevated temperature (120°C). The elastic parameters of the geopolymer were evaluated under triaxial testing. The values were then input into the numerical model to perform a finite element analysis (FEA). Thermal loads were considered when evaluating the effect of temperature on cement performance. Hoop and radial stresses around the wellbore are presented. This study highlights the advantages of the granite-based geopolymer applied in geothermal well conditions.

INTRODUCTION
Global warming is a fact, and green transition is a must. Geothermal energy is a sub-set of geo-energy that has demonstrated its potential in locations such as Reykjavik in Iceland, San Diego in California, and Turin in Italy. The primary cost drivers associated with geothermal energy production are subsurface activities, including well construction and maintaining well integrity. Poor zonal isolation or loss of well integrity can significantly increase the capital and operational expenses associated with geothermal energy production. Zonal isolation is crucial, and cement is the prime material used for well cementing applications in geothermal wells. However, the performance of API class G cement in temperatures above 120 °C is negatively impacted by retrogression and thus excess source of silica is required (Wang et al., 2017). Furthermore, the shortcomings of cement and the environmental impacts of Ordinary Portland Cement (OPC) production have led to the search for alternatives to fully replace OPC (Arbad & Teodoriu, 2020; Carey et al., 2007). Of these materials, one may refer to geopolymers, blended cement, and pozzolanic cement (IEA, 2022).