bluuebunny/crossref_metadata_2025 huggingface dataset:
Injection-Induced Instability of the Fault Gouge
Authors: Geilikman M. B.
Published: September 2022

A number of injection operations such as CCS (carbon capture and storage), DAC (direct air capture), fluid and enhanced geothermal injections (EGS) can lead to fault-system instability which presents significant geohazard. This instability potentially can activate either slow aseismic movement or a rapid seismic slip. Because the fault instability presents substantial environmental damage, we developed a new model which approaches the problem of fault instability by capturing the whole strain-stress response, the post-failure one included which underlines importance of full rock characterization. Our explicit analytical model incorporates post-failure strain-softening into elasto-plastic and visco-ferma (Kelvin) rheology for the fault gouge. The strain-softening rheology itself is necessary but not sufficient for the transition from smooth aseismic movement to the rapid seismic slip. The condition of the onset of rapid slip instability is obtained. The occurrence and magnitude of the rapid slide displacement significantly depend on the shape of the post-failure stress-strain curve. The seismic magnitude and coefficient of seismic efficiency are explicitly computed from the seismic moment and seismic energy, released during the slip. The seismic energy release depends on two control parameters. The first scaling parameter is the energy, released as a result of strain softening. The second dimensionless parameter contains the stiffness of the surrounding (country) rock, the stiffness of the gouge in the post-failure domain as well as geometric factors of the fault and its gouge. The visco-ferma feature of the model allows us to obtain a gradual cross-over between the rapid seismic slide on the fault and slow aseismic fault movement.

1. INTRODUCTION

Injection-induced instability of tectonic faults, which presents significant geohazard, has been addressed in a number of publications, especially recently in connection with Carbon Capture and Storage, or CCS (Verdon, 2014 and references therein), Direct Air Capture, or DAC (Tsuji et al, 2021), as well as for fluid and enhanced geothermal injections EGS (McGarr et al, 2015).
Wellbore Shut-In Temperature Study After Fluid Circulations in a Fit-For-Purpose Research Well in Grimes County, Texas
Authors: Chen G. , Wright C. , Goswami J. C.
Published: September 2022

This paper strives to model and validate annulus fluid and casing temperature profiles during wellbore warmback after fluid circulations. Modeling is based on published analytical methods. A research test well has been drilled to a predefined temperature target which can help validate the modeling results. Multiple live-streaming and memory tools are run to provide downhole temperature measurements during drilling, circulation, shut-in, cementing and post-drilling circulation/shut-in (warmback) operations. A permanent distributed fiber optic (FO) system, installed outside of the production casing, provides continuous downhole temperature measurements.

One open-hole (OH) warmback and two cased-hole (CH) warmbacks were analyzed. The difference between modeled and measured temperature is within 3°F for the two cased-hole cases. With limited bottom hole temperature (BHT) measurements, the difference of the BHT is within 6°F for the open hole case.

Dimensionless temperature studies show that after the dimensionless shut-in time reaches 9 for OH case and 20 for CH case (for the base-case formation thermal diffusivity) the difference between BHT and SFT (static formation temperature) reaches 10% of the difference between the wellbore temperature at the end of the circulation and the undisturbed SFT. For a given wellbore configurations and with 0.03 ft2/h (7.74e-7 m2/s) formation thermal diffusivity, this critical time corresponds to about 49 and 40 hours for the open hole and close hole cases, respectively.

The models and results described in this paper can be applied to temperature log timing determination, geothermal well design, underground energy storage and geothermal recovery processes.

1. INTRODUCTION

A good estimate of annulus fluid temperature in a wellbore plays an important role in drilling operation as well as in determining and possibly extending the operating range of various downhole tools. In geothermal drilling, for instance, most downhole tools involving electronic components become ineffective beyond about 175°C. A properly designed mud chiller or insulated drill pipes can extend the temperature limits. This requires a good thermal management approach. In this paper, we demonstrate the validity of some of the existing analytical models for wellbore thermal profile estimation by comparing them with measured data.
A Comparison of Hydraulic Fracture Front Tracking Algorithms
Authors: Dontsov E. V. , Hewson C. W. , McClure M. W.
Published: September 2022

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

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

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

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

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

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

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

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

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).
Acoustic Response During Brine-CO2 Relative Permeability Testing of Bluff and Entrada Sandstones
Authors: Czarnota R. , Rinehart A. J. , Luhmann A. , Wang S. , Grigg R.
Published: September 2022

We present experimental results of brine and supercritical CO2 (scCO2) relative permeability experiments with active ultrasonic monitoring at reservoir conditions in the Bluff and Entrada Sandstones (NM, USA) from outcrop, which are being considered as possible geologic carbon storage targets, at reservoir conditions. The Bluff and Entrada Sandstones have distinct differences in grain size and cementation composition and amounts. We measured their relative permeability properties curves on outcrop rock using a steady-state method at possible reservoir conditions of elevated temperature and high pressure, i.e., at 85 to 89°C and, 22.8 to 24.1 MPa pore pressure in a CoreLabs Acoustic Core holder. To better understand scCO2 plume migration and residual trapping, both drainage and imbibition relative permeability were measured with increasing and decreasing fractional flows. At every steady saturation reached, we estimated the relative permeability measurement and measured the compressional wave velocity (Vp), and two shear wave velocities (Vs and Vs*) at the 500 kHz using a multichannel pulser-receiver. We found that Vp decreased and Vs and Vs* increased slightly as brine saturation decreased. This is consistent with the literature and further supports using seismic monitoring of the CO2 plume. Most tests revealed hysteresis in Vs and Vs* indicating possibly significant lithology dependent pore-scale processes leading to isolation of portions of the rock. This suggests that, at the laboratory scale, acoustic monitoring may reveal residual trapping mechanisms, transient wetting behavior, and other fluid-framework coupling to shear waves tied to different pore structures and surface chemistry related to the primary and diagenetic fabrics of the rocks.

1. INTRODUCTION

Geological storage of carbon dioxide (CO2) into deep saline aquifers has emerged as a potentially effective way to reduce our emissions of greenhouse gases. Monitoring of multiphase flow properties are needed to characterize the extent of CO2 mobility across the reservoir but are challenging to link to log- and reservoir-scale behavior. Acoustic-based studies measure elastic wave velocities including anisotropy and can be used in the calibration of sonic logs and to inform 3D/4D seismic and microseismic interpretations (Falcon-Suarez et al. 2020). The CO2/brine flow in a saline aquifer has two distinctive borders: 1) plume front where CO2 contacts brine (drainage); (2) after the initial front passes, CO2 is then displaced partially by brine (imbibition). In this study, we link relative permeability and brine/CO2 saturation measurements and variations in acoustic velocities during a cycle of drainage and imbibition.
Impact of Oil Based Mud on Chemo-Mechanical Properties of Cuttings and its Treatment
Authors: Martogi D. , Prakash R. , Varanasi V. R. S. B. , Abedi S.
Published: September 2022

In this study, we investigated the chemo-mechanical properties of cuttings contaminated with oil-based mud (OBM) and its various treatments. Rock fragments are obtained from Eagle Ford and Marcellus formations, which are then cut into cuttings with sizes ranging from 4 mm to 8 mm. The Eagle Ford sample is a carbonate-rich organic free sample, while the Marcellus sample contains a mixture of Calcite, quartz, and clay. We contaminated each sample with OBM under controlled pressure and temperature conditions. We then cleaned the samples using several treatment methods: wiped with cotton buds, soaking in a solvent, and soaking in diesel. Chemo-mechanical properties before and after contamination of each sample were then studied using micro-indentation technique and scanning electron microscopy-energy dispersive X-ray spectrometry (SEM-EDS). In doing so, the analysis was performed on samples’ cross-sections to study properties changes across the depth of contamination. A discussion on mechanical and chemical evolution across the sample depth will be presented. Degradation in mechanical and compositional properties are observed most severely on samples treated by solvent soaking. Wiping off OBM from the samples surface was found to preserve samples’ chemo-mechanical properties the most. Higher cuttings to OBM contamination ratio and higher cuttings to solvent ratio were observed to have more adverse effects on cuttings integrity.

1. INTRODUCTION

Completions quality is an essential factor in evaluating the economic viability of a reservoir. Completions quality relies on a good understanding of rock mechanical properties (i.e., elastic, strength, and fracture properties), the in-situ stress magnitudes, orientations, anisotropy, and rock mineralogy to determine the most effective completions design and treatment (Prioul et al. 2016, 2018). Typically, these properties are measured through laboratory testing on cores, outcrops, and well logging. Though cores are preferred, they are only acquired on a select number of wells due to cost and are typically taken on the vertical section of the wells. Well loggings are usually performed on select wells during the exploration phase and are limited to acquisition resolution. Drill cuttings, however, are continuously collected and transported to the surface throughout drilling and are available throughout the vertical and lateral sections of the well at no additional cost. Cuttings have been shown to be a valuable resource for determining petrophysical properties (i.e., permeability, organic content, porosity, density, mechanical properties) in cases where cores collection and logging are not economically viable and technically challenging (Ortega et al., 2012; Olusola et al., 2014; Prioul et al., 2016; Althaus et al., 2020; Sanei et al., 2020).
Optimal Design Method of Oscillator Installation Position in Sliding Drilling
Authors: Shi Xiaolei , Huang Wenjun , Gao Deli , Yang Guang , Wang Wenzhi
Published: September 2022

In the process of sliding drilling, installing oscillators on drill strings can decrease axial friction and increase wellbore extension effectively in sliding drilling. Traditionally, the positions of oscillators are most determined by drilling experience, which constraints the drag reduction efficiency of oscillators. To overcome this shortcoming, a new optimization design method of oscillator installation position is presented. Firstly, the initial position of the drill bit is determined according to the well structure data, drilling parameters and drilling time. Then, the drill string in the borehole is divided into key nodes according to the joint position. Based on the data of screw induced torque, the action length of screw induced torque is calculated, and the action length of static friction zone is determined. Next, based on the initial conditions and boundary conditions, establishes a dynamic model of drill string by considering the friction nonlinearity and uses finite difference method to solve it, the friction distribution of drill pipe is analyzed, and the friction of key nodes in each distribution area is calculated. Finally, the initial position of the drill bit and the action length of the static friction zone are re-determined, and the friction of key nodes is accumulated. By analogy, the maximum accumulated friction in the static friction area is determined. Based on the oscillator’s propagation distance model and the minimum drag reduction efficiency, the recommended best installation position is calculated, and sensitivity analysis is carried out to evaluate the drag reduction effects of various parameters. The results show that, compared with the calculation results of determining the installation position of oscillator by drilling experience in the past, the model in this paper has a more significant effect on reducing friction and the installation position is more reasonable. The fluctuation of the displacement of drill string and the hook load are more obvious when the oscillators are installed in the preferred position, and the effect of reducing the average friction is significant, which is more conducive to the transfer of axial force. When other parameters are constant, using the recommended positions of oscillators or increasing the number of oscillators can not only beneficial to the transmission of axial force, and can reduce the average friction of the drill string, but also improve the drag reduction efficiency of the drill string, increasing the rate of penetration and increasing the borehole extension distance. The research results are of significant guiding significance for optimal design and safety control of drag reduction oscillators in sliding drilling.
Micromechanical Modeling of Shale-Indentation Experiments Imaged by Synchrotron X-Ray Micro-Tomography
Authors: Rutqvist J. , Voltolini M. , Kneafsey T. J.
Published: September 2022

We present micromechanical modeling of an indentation experiment on Green River Shale with simultaneous X-ray micro-computed tomography of internal sample deformation that provides new insights into the ductile-brittle micromechanical behavior of shales relevant to proppant embedment. Brittle wing cracks appear from the indenter along the shale bedding, but indentation depth is dominated by ductile plastic shear deformations governed by extreme compressive stress magnitudes below the indenter-shale contact. Simultaneous analysis of the experimental loading-unloading indentation curves and the imaged shale deformations were used to constrain elasto-plastic properties and strength anisotropy of the tested Green River shale sample.

1. INTRODUCTION

The evolution of rock fractures and their fluid transmissivity are critical in underground energy geosciences activities, such as hydrocarbon production, carbon sequestration, geothermal energy, and nuclear waste disposal (Rutqvist and Stephansson, 2003). The fluid transmissivity of a fracture depends on factors such as the local stress across the fracture, fracture surface roughness, shear displacement offset, and host rock properties (Barton et al., 1985). In hydrocarbon production, proppants such as sand are frequently injected into fractures to keep them open for enhanced hydrocarbon production (Kadende et al., 2021a). However, even proppant-filled fractures may close significantly because of embedment of the proppant into the fracture surfaces and proppants may also be crushed under high stress (Kantende et al., 2021b). The embedment of proppants may be particularly severe in shales high in organic carbon or clay, shales that may be characterized as self-sealing (Bourg, 2015).

In this study we present micromechanical modeling of an indentation experiment on a soft Green River shale of high organic carbon content. The experiment was conducted under simultaneous synchrotron X-ray micro-computed tomography to image internal three-dimensional sample deformation. This include tomographic images of internal deformation anisotropy, fracturing, and surface pileup adjacent to the indenter. The modeling presented in this paper shows that matching the experimental loading-unloading indentation curves and the shale deformation field in three dimensions can be used to constrain elasto-plastic properties and strength anisotropy of the tested shale sample. The work also provides new insights into the ductile-brittle micro-mechanical behavior of shales relevant to proppant embedment.
Cooling-Induced Acoustic Emissions in Westerly Granite: Implications for in Situ Stress Measurement
Authors: Trzeciak M. , Sone H. , Wang H. , Nakagawa S. , Voegeli S.
Published: September 2022

Thermally induced stress changes in rock lead to creation and reactivation of microcracks with accompanying acoustic emissions (AEs). Therefore, monitoring AEs during cooling (or heating) of rock potentially allows us to determine the rock’s original stress state. This approach would require predicting time-dependent changes in the thermally induced stress and applying an appropriate AE-based failure criterion, so that the in situ stress can be determined by subtracting the induced stress from the failure stress. The goal of this research is to develop a technology to determine the stress state in geothermal reservoirs by cooling the borehole circumference and detecting the onset of microscale rock failure. As the first step to achieve this goal, we examined spatio-temporal evolution of AEs which were thermally induced in Westerly Granite blocks by abrupt local cooling. Four sets of experiments were conducted with different sample and cooling geometry, stress state, and preexisting damage (cracks). The preliminary results indicate that the onset of AE activity can be correlated best to the thermal front propagation in rock samples and to the applied stress. Interestingly, pre-existing microcrack damage in rock had little impact on the AE onset behavior. The conditions that lead to the onset of AE activity and its relation to the ultimate tensile strength of rocks – a parameter which is determined from conventional rock testing – are still poorly understood, which requires further investigation.

1 INTRODUCTION

Sustainable development of geothermal energy resources requires detailed knowledge about the in situ stress state in the target rocks. In deep boreholes, stress estimation commonly relies on analysis of wellbore wall failures, break-outs and drilling induced tensile fractures, which develop spontaneously after the well is drilled (e.g. Zoback et al., 2003). Active methods of stress measurement are usually limited to hydraulic methods for estimation of the least principal stress (De Bree and Walters, 1989). Several methods of active stress measurement, capable of constraining the entire stress tensor have been proposed, e.g. overcoring (Worotnicki, 1993), hydraulic tests on preexisting fractures (HTPF) (Cornet, 1983), or sleeve fracturing (Stephansson, 1983). However, each of these methods has their associated technical difficulties or deficiencies which make them unpopular in practical application in deep environments.
An Integrated Geology-to-Geomechanics Workflow to Assess Geomechanical Risk of CO2 Geological Storage
Authors: Sun Zhuang , Cosson Camille , Plougoulen Aurore , Datye Deepak , Fager Andrew , Crouse Bernd
Published: September 2022

Full-scale implementation of CO2 storage requires a number of challenges to be addressed, among them is reliably assessing geomechanical risk at storage sites. A 3D mechanical earth model (MEM) can be used to understand how rock types and stresses are distributed in the 3D space of the reservoir and surrounding formations. However, due to meshing limitations, the MEM is typically derived from simplified geological frameworks and does not relate with static and flow simulation models anymore. To overcome these difficulties, we have developed a general solution to readily assess the geomechanical risk of CO2 geological storage while preserving the geology’s integrity. We present a case study based on an offshore field in which the storage formation is composed of stacked anticlinal sandy layers sealed by shaly caprocks. We investigate fault stability by explicitly simulating the fault slippage and observe a significant fault reactivation with a maximum magnitude of ~ 0.3 m. A high resolution sub-model of the near-wellbore region indicates a stable wellbore condition. This workflow permits us to combine a reliable representation of the subsurface with a state-of-the-art rock mechanics finite element solver, which can be leveraged across the entire lifecycle of CO2 storage.

1. INTRODUCTION

CO2 geological storage is a proposed solution to curb carbon emissions to the atmosphere (Bachu, 2008; Benson and Cole, 2008; Bickle, 2009). A large-scale CO2 storage project requires annual CO2 injection of millions of tons into deep geological media where the caprock and faults provide structural trapping of CO2 (Michael et al., 2010; Fuss et al., 2014; Tang et al., 2021; Wu et al., 2021). However, full-scale implementation of CO2 storage requires a number of challenges to be addressed, among them is reliably assessing geomechanical risk at storage sites (Rutqvist, 2012). For instance, CO2 injection increases the pore pressure and reduces the effective stresses, which may reactivate existing faults or induce damaging geomechanical changes to the caprock (Cappa and Rutqvist, 2011; Faulkner et al., 2018; Ju et al., 2021; Sun et al., 2021b). Fault reactivation is one risk of CO2 storage because it may compromise the sealing behavior as well as induce seismic events (Zheng et al., 2009; Apps et al., 2010; Zoback and Gorelick, 2012). Therefore, it is critical to maintain the integrity of caprock and faults to ensure the long-term CO2 storage security.
The Comprehensive Effects of Group Fracturing and Depletion Redistribution in Low Permeable Reservoirs
Authors: Qu H. Y. , Lang H. , Xue X. J. , Da Y. P. , Zhou F. J. , Liu X. Y.
Published: September 2022

Refracturing is an effective way to drain the unstimulated rock through diversion treatment. The refrac geometry is determined by the reorientation and change in the magnitude of the in-situ stress. However, the comprehensive impact of primary fracturing, water injection and oil production in well group on the stress redistribution has not been well understood. A three-dimensional heterogeneous geomechanical model coupled with unconventional fracturing and reservoir simulation was established. Following the primary hydraulic fracturing and water injecting according to the pumping and injection schedule of an inverted nine-spot well group, an automatic gridding algorithm was run. In addition, history match and 10-year production prediction were conducted through reservoir simulation. A 3D geomechanical finite element solver was utilized to compute the spatial and temporal change in the in-situ stress and deformation during fracture propagation and reservoir depletion, providing updated stress profiles. Refrac simulation scenarios were run after production of 1 year, 3 years, 5 years and 9 years to identify the most opportune time to refrac the well group. Results indicate that the impact of water injection on stress is consistent with hydraulic fracturing while opposite to that of the reservoir depletion. The magnitude of horizontal principal stresses increases around the injection well, while the stress contrast decreases during the water injection. Hydraulic fracturing induces tensional and compressional stress perturbation around the producing well in the vicinity of fracture tips and fracture walls while the stress is released as the well produces. In addition, the magnitude of stress variation in the well group increases with the depletion at the beginning, followed by a decrease. It is beneficial to refrac the well group 3 years after the first treatment. The impact of water injection, primary hydraulic fracturing and well depletion on the variation of in-situ stress was clarified through an integrated modeling in this study, providing insights for the design and evaluation of refracturing treatments to enhance the field development of the low permeable reservoirs.