bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Comparison of Hydraulic Fracture Front Tracking Algorithms
Authors: Dontsov E. V. , Hewson C. W. , McClure M. W. 
Published: September 2022

ABSTRACT:
Hydraulic fracture simulation is a viable tool for optimizing treatments in the field. Current large scale developments create a need for more efficient modeling approaches, which are capable of simulating pad-scale projects. One way to boost computational efficiency of a hydraulic fracturing simulator is to use a coarser mesh. This, however, can noticeably affect accuracy. Traditionally, hydraulic fracturing simulators incrementally propagate fracture by adding one element at a time or by breaking a bond to effectively create a fracture element. The former is the case for displacement discontinuity based methods, while the latter corresponds to finite element and discrete element methods. In this situation, the fracture geometry is inherently quantified within the error bound of a single element size. Alternatively, to reduce this error, one may employ a front tracking algorithm, in which the fracture position varies continuously as a function of the fill of the element. To better understand potential benefits, the purpose of this study is to evaluate accuracy of two hydraulic fracture front algorithms, namely the one with Multi Layer Tip Elements (MuLTipEl) and Implicit Level Set Algorithm (ILSA). Both of these algorithms use the tip asymptotic solution to advance the fracture front, but use very different logic underneath. A series of benchmarking numerical examples with various meshes and the degree of complexity is performed to reveal advantages and limitations of these approaches.

1 INTRODUCTION
Hydraulic fracture models are often used to help understanding and optimizing processes occurring in the underground formations. With the development of modern shale plays, the problem scale increased dramatically. Numerous wells are typically drilled within a pad, each of which is then hydraulically fractured with tens of stages. This puts enormous pressure on fracture modeling to become more efficient and allowing to simulate large scale problems. To address the issue, one possibility is to use a coarser mesh, which clearly boosts computational performance. This, however, often leads to inaccurate results. An alternative is to use more sophisticated models that are able to deliver relatively accurate results even on a coarse mesh. In the context of hydraulic fracture modeling, this involves fracture front tracking algorithms as they allow to more accurately describe geometry of hydraulic fractures. The aim of this paper is therefore to evaluate and compare performance of two available fracture front tracking algorithms with respect to accuracy for several benchmarking cases.
Quantifying Flux-Induced Sanding in Oil and Gas Wells
Authors: Xiao Yuxing , Zhou Xiaoxian , Vaziri Hans H. 
Published: September 2022

ABSTRACT:
Following rock disaggregation, sanding in oil and gas wells is principally driven by the fluid flow induced drag forces overcoming frictional resistance of rock aggregates. The empirical Hill-Koch-Ladd (HKL) correlation of viscous drag force to the Reynolds number, fluid flux, fluid mechanical properties and particle size widely used in chemical engineering is employed to assess the flux effect on sanding in this paper. It is illustrated that the viscous drag around the near perforation area is much larger than the pressure drag in the gas flux range commonly encountered in wells and thus its impact on sanding cannot be ignored. The HKL correlation has been incorporated into an existing finite element numerical sanding prediction model within the framework of the Biot’s general consolidation theory to quantify field-scale flux-induced sanding. The improved numerical model explicitly considers both the viscous drag and rock disaggregation with reservoir pressure depletion. It captures many field observations of practical significance including effects of aggregate size, fluid flux, and the overall trend of sanding with reservoir pressure depletion and natural decline of well flow rate with time. One set of field cases presented involves two weak reservoir formations in two fields with distinctly different average particle sizes, gas flux range and sanding responses. It is used to illustrate the numerical model’s capability to capture the effect of rock aggregates size and gas flux. The combined effect of flux and gradual rock disaggregation is demonstrated through another field case involving a strong reservoir formation. The numerical modeling results can be used to better optimize well sandface completion design, and short- and long-term well hydrocarbon production.

1. INTRODUCTION
There are two prerequisites for sanding to occur in the field. The first one is that rock needs to be disaggregated from its intact state. Field-scale rock disaggregation is a gradual process and primarily driven by reservoir pressure depletion and sandface drawdown. Xiao et al. (2011) describes a practical approach to approximate field-scale rock disaggregation and corresponding mechanical strength degradation beyond the conventional concept of strain softening and its impact on sanding. The second prerequisite is that fluid flux needs to exceed certain limit. The fluid flux is the fluid flow rate per unit length of completed reservoir formation intervals along the wellbore. Its practical units commonly used include million standard cubic feet per day per foot (mmscfd/ft) in gas wells and barrels per day per foot (bpd/ft) in oil wells, and can be converted to fluid flow velocity in meter per second (m/s) on the sandface through sandface completion geometries, e.g. the perforation density in shots per foot and perforation entry hole diameter (EHD) in a cased and perforated (C&P) completion, along with fluids PVT properties.
Coupled THM Modelling of Induced Seismicity Associated with Geothermal Fluids Re-Injection: The Role of Transient Cooling-Induced Permeability Enhancement
Authors: Cao W. , Durucan S. , Shi J. Q. , Korre A. , Ratouis T. 
Published: September 2022

ABSTRACT:
Seismicity induced by injection of energy depleted geothermal fluid, as well as field injectivity, has been observed to be inversely correlated with the temperature of re-injected fluids at the Hellisheiöi geothermal field, Iceland. Using the Hellisheiöi field injection data, transient cooling-induced permeability enhancement as a distinctive mechanism for induced seismicity in geothermal reservoirs was investigated. A 3D coupled THM model was developed to model the colder fluids re-injection process over a 1-year period and evaluate the potential for induced seismicity at Hellisheiöi. Three modelling scenarios considering respectively the poroelastic effect, thermoporoelastic effect, and thermoporoelastic effect with permeability enhancement, were examined and compared to identify the dominant mechanism for induced seismicity and examine the contribution from each individual mechanism. Results have shown that, under normal fluid re-injection pressure and temperature conditions, the permeability enhancement effect is the dominant mechanism for induced seismicity at Hellisheiöi. In addition, by reducing temperature of re-injected fluids from 120 °C to 20 °C, the amount of heat transferred can be increased by 8.4 times, which explains the high sensitivity of induced seismicity to temperature. The findings of this work suggest that temperature control of injected fluids can be a feasible regulation method to mitigate injection-induced seismic risk.

1. INTRODUCTION
Induced seismicity has long been a major challenge faced by the geothermal industry, as well as other industries concerned with fluid injection into or resources extraction from the subsurface. In addition to adverse physical effects on buildings and facilities in the surrounding communities, the magnitude and intensity of injection-induced seismicity associated with current and future geothermal exploitation remain a great public concern.
Typical mechanisms identified for induced seismicity in geothermal environments include fluid pore pressure increase, poroelastic stressing, thermoelastic stressing, and chemical alteration of frictional properties of fractures (Majer et al. 2007; Rathnaweera et al. 2020). As a specific mechanism relevant to geothermal systems, the thermoelastic effect has been of particular research interest in recent years (e.g., Jeanne et al. 2014a). The thermoelastic stress change, analogous to the poroelastic stress change, influences the occurrence of induced seismicity by changing the prevailing stress states.
Factors Influencing the Initial State of Stress of Cement Annulus
Authors: Meng Meng , Frash Luke , Carey J. William , Zhang Weicheng , Li Wenfeng , Welch Nathan 
Published: September 2022

ABSTRACT:
Cement initial effective stress is defined as the state of stress after waiting on cement (WOC). Many factors can affect cement’s initial effective stress distribution, including formation environment, cement formulation, and hydrostatic pressure. Our recent experiments using a plug shape setup show that under high-pressure conditions, cement initial effective stress at the cement-casing interface usually drops below hydrostatic pressure but higher than zero, and cement permeability is in the range of nano-Darcy. In a typical cement annulus geometry, we care about initial stress at both the cement-casing interface and the cement-formation interface. The total stress and pore pressure distribution across the annulus may not be isotropic. Therefore, the initial effective stress in the radial direction may not be the same. This non-isotropic initial effective stress distribution places the cement-casing interface and cement-formation interface at different levels of risks under pressure and temperature oscillations caused by carbon injection into the subsurface through wells.

1. INTRODUCTION
Cement’s initial state of stress has confused the petroleum industry for decades. The initial state of stress includes total stress, pore pressure, and effective stress. The total stress determines the carbon leakage threshold at the interface, while the effective stress controls the poromechanical response of cement during carbon injection through wells (Meng et al., 2021a). The total stress and effective stress may or may not show consistent behavior considering the effect of cement pore pressure.
Accurately understanding initial stress is essential to well plugging & abandonment and maintaining well integrity in carbon sequestration wells. The initial stress has proven to strongly affect cement failure (Saint-Marc et al., 2008; Bois et al., 2012; Meng et al., 2021b). Working on well integrity simulations, most researchers either assume initial effective stress as zero (Zhang et al., 2017), or equal to hydrostatic pressure when cement is in a liquid state (Gray et al., 2009; Nygaard et al., 2014). Such discrepancy in assumption causes great uncertainty in analyzing safe operational windows for maintaining well integrity during carbon injection.
Acoustic Emission Monitoring of Thermal Cycling in Salt at the Waste Isolation Pilot Plant
Authors: Choens R. C. , Kuhlman K. L. , Herrick C. G. , Otto S. 
Published: September 2022

ABSTRACT:
A series of field-based multi-physics observations were conducted as part of the Brine Availability Test in Salt (BATS) underground at the Waste Isolation Pilot Plant (WIPP), near Carlsbad, NM. Observations were made of brine production, temperature, electrical resistivity, acoustic emissions (AE), and gas/liquid tracer migration through salt around twin heated/unheated borehole arrays.
Here, we present AE results from thermal cycling experiments performed May - July 2021, during which the heater was pulsed several times followed by two longer heated periods. Sixteen AE sensors were installed in three parallel observational boreholes surrounding the central heated borehole. Observed AE demonstrate that heating and cooling cycles significantly impact salt behavior. AE rates increased during heating and increased further upon cooling. Average energy and frequency bandwidth also increased during heating and cooling of salt. Similar behavior was observed for each heating/cooling cycle, suggesting that temperature-enhanced salt healing may have eliminated any threshold loading associated with the onset of AE (i.e., the Kaiser effect). Locations of AE events remained centralized around the borehole. These results show that AE provide valuable information about the thermal behavior of salt, particularly that cooling of salt results in the highest AE behavior.

1. INTRODUCTION
The Waste Isolation Pilot Plant (WIPP) outside of Carlsbad, NM is the nation’s only active geologic repository for nuclear waste. Currently, WIPP is licensed to dispose of transuranic radioactive waste from defense activities. The US Department of Energy Office of Nuclear Energy’s (DOE-NE) Spent Fuel and Waste Science and Technology program is pursuing generic research into multiple possible disposal media (i.e., salt, argillite, and crystalline rocks) for heat-generating waste from spent nuclear fuel. The DOE Office of Environmental Management (DOE-EM) that manages the WIPP site provides access to the WIPP underground DOE-NE work that is testing the behavior of the generic bedded salt under conditions relevant to spent fuel and high-level waste disposal.
Shear Waves Anisotropy and Image Logs Integration for Improved Fracture Characterization
Authors: Ifrene Ghoulem E. H. , Irofti Doina , Khetib Youcef , Rasouli Vamegh 
Published: September 2022

ABSTRACT:
Natural fractures aperture and porosity have a significant impact on the quality and production of naturally fractured tight reservoirs. The existence of fractures that channel fluids towards the wellbore enhances the productivity of the field. In this context, near wellbore fracture characterization is a key parameter for accurate discrete fracture network (DFN) modelling and therefore evaluation of fractured reservoirs productivity. In this paper, fracture parameters are estimated using coupling of advanced logging tools in the Cambro-Ordovician tight sand reservoir situated in the Central Ahnet basin, Algeria, where natural fracturing is critical and plays a key role in reservoir production. Cores are expensive and their recovery in highly fractured reservoirs is limited. In addition, the non-oriented cores, and the difficulty to expose them to downhole conditions make the use of the image logs analysis more valuable. As a first step, fractures were identified and evaluated using the FMI images and 498 natural fractures were discerned. The integration of Sonic Scanner allowed a reclassification of the fractures to 267 open and 231 closed fractures based on the interpretation of anisotropy dispersion curves obtained from the three wells. An advanced processing workflow was executed on the open fracture traces observed on the FMI logs in order to estimate the kinematic and hydraulic aperture of the fractures. The results obtained were used to characterize fracture porosity. Three sets of open natural fractures were identified based on their orientations and apertures.

1. INTRODUCTION
Naturally fractured reservoirs are found all over the world and contain considerable volumes of oil and gas reserves. The study of fluid flow and transport processes in fractured porous media has attracted lots of interest over the last half-century and has been one of the most active areas in examining flow in subsurface reservoirs (Wu, 2016). Highly fractured reservoirs are generally due to the complex tectonic activities and their characterization is a recurring challenge. The interconnected fracture network ensures the flow of fluid at large scale and the fracture system (i.e., aperture, spacing, etc.) needs to be characterized in order to understand and simulate the fluid flow process. Discrete Fracture Network (DFN) models are constructed to help with field development and optimization, and this need an accurate integration of natural fractures in the near-wellbore regions to improve the inter-well fracture prediction by involving and combining various advanced well logging technics such as, high-resolution image logs and sonic scanner (Rezig et al., 2018).
A Fully Coupled Porochemoelastic Modeling for Borehole Stability in Chemically Active Porous Media
Authors: Gao Jiajia , Wang Zhe , Wang Pingquan , Chen Fuzhi , Peng Hao 
Published: September 2022

ABSTRACT:
This paper presents a new fully coupled Hydro-mechanical-Chemical (HMC) model also accounts for the ultrafiltration effect resulting from pressure gradient in the expression of the solute mass flux. Based on this new HMC model, one derives a set of analytical solutions considering the fully coupled porochemoelastic responses for drilling an inclined borehole. Using the new solutions conducts several studies of the ultrafiltration effect on pore pressure, stress, and the time-dependent shear failure behaviors including intact rock matrix and weak plane around a horizontal borehole drilling through the shale formation. The results show that the ultrafiltration effect increaces the mud weight required to avoid borehole collapse when the solute mass fraction ( or solute concentration) of drilling mud is larger than that of the formation fluid. The location of borehole breakout does not always occur at the borehole wall. It initiates inside the formation at an earlier time whereas returns to the borehole wall with increasing time. This regularity is exactly in response to the corresponding variations of pore pressure and effective stresses.

1. INTRODUCTION
Borehole stability is in principle controlled by the field variables around a borehole drilling through a porous rock (Gao et al. 2021). In the case of drilling chemically active porous shale formation, the main field variables associated with the pore pressure and stresses are disturbed and reestablished due to differences including pressure, solute/solvent mass-fraction (concentration or activity), and stresses at the borehole wall between pre-drilling and post-drilling. The solute mass-fraction (concentration or activity) difference is compared between the pore fluid of shale formation and drilling mud. Studies for the variations of field variables have been made with respect to the poroelastic effect (Detournay and Cheng, 1988), chemical osmosis effect resulting from solute mass-fraction(concentration) difference (Heidug and Wong, 1996; Ghassemi and Diek, 2003; Yu et al., 2003; Ekbote and Abousleiman, 2006; Roshan and Rahman, 2011; Kanfar et al., 2016), and water activity difference (Mody and Hale, 1993; Nguyen et al.2009).
Stability Analysis of Pillars Between Bedded Salt Cavern Gas Storage Groups Under Triangular Well Layout
Authors: Cai Rui , Ma Hongling , Liang Xiaopeng , Zhao Kai , Yang Chunhe 
Published: September 2022

ABSTRACT:
Salt caverns have low porosity, low permeability, self-healing damage, high plastic deformation ability, simple hydrogeological conditions and wide distribution. Salt rock deposits in China are mainly multi-layer salt rock. The characteristics of salt formations present challenges to the design and safety evaluation of reservoirs in multi-layer salt rock deposits. In this paper, the numerical simulation method is used to establish a three-dimensional numerical model of the layered rock-salt cavern gas storage in the Jintan Salt Mine, Jiangsu Province, and the strain softening model is used for numerical calculation. According to the influence laws of the plastic zone, the maximum displacement around the cavern, equivalent strain and volume shrinkage rate, the stability of the salt cavern gas storage when the wells are arranged in a triangle pattern is analyzed. And the pillar width of the salt-cavern gas storage is optimized. The comprehensive results show that the plastic zone, maximum displacement around the cavern and volume shrinkage rate increase with the increase of the pillar width when the wells are arranged in a triangular well pattern. The suggested widths of pillars are 1.60 times of salt cavern diameter. This study provides basic data and reference for engineering problems such as optimizing the pillar distance of the newly built cavern, increasing the number of wells in the salt cavern mining area, and increasing the storage capacity of the salt cavern gas storage.

1. INTRODUCTION
In recent years, with the adjustment of the domestic energy structure, natural gas, as a relatively low-emission green energy, plays a more important role in improving air quality, improving energy efficiency and maintaining sustainable economic development. The demand for natural gas in China continues to increase, and the "coal-to-gas" conversion in some northern areas has resulted in a "gas shortage", exposing the problem of insufficient natural gas reserves in my country. The important role of underground gas storage in energy supply has been paid more and more attention (Wang et al., 2011).
Haze, Rain and Temperature Inversion in Gas-Storage Salt Caverns
Authors: Bérest P. , Louvet F. 
Published: September 2022

ABSTRACT:
The brine sump at the bottom of a gas-storage cavern remains perennially colder than the rock mass at cavern depth, even a dozen years after cavern creation has been completed, resulting in an inversion of the temperature gradient in the lower half of the cavern in which convection is impeded. The origin of this is the presence of water vapor in the cavern. A cycled cavern is a thermodynamic device that consistently cools the brine sump. After rapid depressurization following a period during which gas is saturated with vapor: the gas temperature drops, oversaturating the gas; and condensation takes place in the entire gas mass from which the heat required for condensation is withdrawn uniformly. Conversely, following a rapid pressure increase: the cavern gas warms, undersaturating the gas with vapor; and vaporization occurs at the brine-gas interface, yielding to cavern sump cooling.

1. SALT CAVERNS USED FOR GAS STORAGE
Salt caverns are solution mined from salt formations. They provide storage capacity for liquid or gaseous hydrocarbons. Large-scale storage of compressed air or hydrogen in such caverns is anticipated. These caverns are connected to ground level through a 200-m to 2000-m cemented casing (Fig.1a). Their volume is several hundred thousand m3. A hanging string is set in the well, similar to a straw in a bottle; water is injected in the cavern through the hanging string; and the formed brine is removed from the cavern through the annulus between the hanging string and the cemented casing. When solution mining is completed, the cavern is filled with brine. In the case of gas storage, gas then is injected in the cavern through the annulus ("debrining", Fig.lb), pushing downward a brine-gas interface in the cavern (Brine is withdrawn through the hanging string.) until the interface reaches the lowest end of the central string. The cavern bottom is filled with insoluble debris that accumulated there during leaching. Sticking the hanging string in the insoluble debris must be avoided, as this string is removed from the cavern at the end of debrining (Fig. 1d). For this reason, the string end must be set slightly above the debris, causing some brine unavoidably to be left at the cavern bottom (Fig. 1c).