bluuebunny/crossref_metadata_2025 huggingface dataset:
A New Perspective for the Conception of Mechanical Earth Model Using Machine Learning in the Volve Field, Norwegian North Sea
Authors: Berrehal B. E. , Laalam A. , Chemmakh A. , Ouadi H. , Merzoug A. , Djezzar S. , Boualam A.
Published: September 2022

Building a mechanical earth model (MEM) is a challenging task. It requires an extensive collection of data such as logs and core data to build a reliable model. MEM can support decision-making and assuaging the risks linked to wellbore stability, saltwater disposal, CO2 sequestration, fault slippage and induced seismicity. Obtaining the data required to build MEM relies on several costly and time-consuming operations such as core sampling, laboratory analysis, various well logs and well testing. This is while there are instances where data is not available. Therefore, a question arises in regards to the possibility of computing the latter critical components in a relatively less demanding manner using drilling related data. According to the literature, there is a direct relationship between data measured during drilling and actual rock behavior. These relationships, although complex, can be mapped using the combined power of machine learning and data analysis, resulting in accurate real -time estimates during drilling. In this paper, we employ a versatile set of machine learning and deep learning models to accomplish the latter.

1. INTRODUCTION

The estimation of stress is a critical component in any geomechanics study. Stress estimation can be applied in several ways in the oil and gas industry. For instance, wellbore stability, where the stress concentrates around the wellbore. Fault stability and induced seismicity, the effect of depletion, the hydraulic fracturing growth and containment, and recently the fracture-driven interaction and poroelastic stress changes due to injection during storage (CO2 and water disposal wells) (Zoback, 2007)

There are several approaches for stress estimation documented in the literature. Zoback (2007) suggests the use of frictional limit theory calibrated to diagnostic fracture injection test (DFIT), mini frac, leak of the test (LOT), or Extended Leak off test (XLOT). Sayers et al. (2010) explained the process of estimating stress for an isotropic and an anisotropic medium from logs and core data. The process needs density and sonic logs and, from that, estimates four components (Ostadhassan, 2013):

• Overburden Stress

• Elastic properties (Young's modulus, Poisson's ratio, Biot Coefficient)

• Pore pressure

• Horizontal stresses (minimum horizontal stress and maximum horizontal stress)

Overburden stress is calculated by integrating the density log from surface to depth z. computing the latter is relatively simpler in regards to the remaining components. The logs calculation results in a dynamic property that needs to be calibrated to a static one using core laboratory experiments. A data that is expensive to get. The pore pressure can be estimated from drilling activity; however, in low permeability formations such as shales, estimating the pore pressure is complicated.
Permeability Changes of Damaged Rock Salt Adjacent to Inclusions of Different Stiffness
Authors: Anwar Ishtiaque , Stormont John C. , Mills Melissa M. , Matteo Edward N.
Published: September 2022

Rock salt is being considered as a medium for energy storage and radioactive waste disposal. A Disturbed Rock Zone (DRZ) develops in the immediate vicinity of excavations in rock salt, with an increase in permeability, which alters the migration of gases and liquids around the excavation. When creep occurs adjacent to a stiff inclusion such as a concrete plug, it is expected that the stress state near the inclusion will become more hydrostatic and less deviatoric, promoting healing (permeability reduction) of the DRZ. In this scoping study, we measured the permeability of DRZ rock salt with time adjacent to inclusions (plugs) of varying stiffness to determine how the healing of rock salt, as reflected in the permeability changes, is a function of the stress and time. Samples were created with three different inclusion materials in a central hole along the axis of a salt core: (i) very soft silicone sealant, (ii) sorel cement, and (iii) carbon steel. The measured permeabilities are corrected for the gas slippage effect. We observed that the permeability change is a function of the inclusion material. The stiffer the inclusion, the more rapidly the permeability reduces with time.

1. INTRODUCTION

Rock salt is being considered as a medium for energy storage and radioactive waste disposal (Schulze, Popp, & Kern, 2001; Tsang, Bernier, & Davies, 2005; Yang, Daemen, & Yin, 1999) due to its extremely low permeability and low porosity. During the construction and/or facility operations, a Disturbed Rock Zone (DRZ) or Excavation Damaged Zone (EDZ) develops in the immediate vicinity of the excavation, with an increase in permeability (Gevantman & Lorenz, 1981; Schulze et al., 2001; Tsang et al., 2005). The increased permeability of the DRZ alters the migration of gases and liquids near the excavation.

Due to the deviatoric stress state that develops around excavations, rock salt creeps. When creep occurs adjacent to a stiff inclusion such as a concrete plug, it is expected that the stress state near the inclusion will become more hydrostatic and less deviatoric, promoting self-healing (Gevantman & Lorenz, 1981; Yang et al., 1999) of the DRZ, including permeability reduction. Healing adjacent to a concrete plug would limit bypass of the plug through the DRZ and thus be conducive to establishing a more effective seal system.
An Analytical Model for Fracture Pressure of Injection Well in Weakly Consolidated Sandstone Considering Wellbore Plugging and Formation Damage
Authors: Li Shuqian , Deng Jingen , Deng Jiutao , Liu Wei , Yan Xinjiang , Hou Zening
Published: September 2022

Weakly consolidated sandstone reservoirs generally feature poor cementation, low strength, relatively high porosity and high permeability. Due to the significant effect of poroelasticity, stress redistribution resulting from the pore pressure perturbation around the injection well should be accounted for when determining the fracture pressure. During the long-term water injection, a flow barrier may form due to large particles plugging on the wellbore wall, likewise, the formation permeability around the well may suffer damage due to fine particles plugging the pore channels. Additionally, tensile failure and shear failure may occur in the weakly consolidated sandstone reservoirs since the pore pressure increases around the injection well. In this paper, we provide an analytical method for fracture pressure calculation of directional injection wells in weakly consolidated sandstone incorporating the effects of wellbore plugging and near-wellbore damage. Wellbore plugging and near-wellbore damage are exacerbated as the water injection, which leads to an increase in the fracture pressure. This paper provides a theoretical reference for the prediction of injection pressure in weakly consolidated sandstone.

1. INTRODUCTION

The calculation of the water injection pressure in the oilfield should consider the tubing friction resistance, the pressure loss of the water distribution nozzle, the liquid column pressure and the fracture pressure (Li, 2005). The pressure loss along the wellbore and the bore-hole hydrostatic pressure are available when the amount of water injection is determined. Consequently, calculating the reservoir fracture pressure is the premise for ascertaining the water injection pressure. For the fracture pressure, the actual measured value obtained by the mini-fracturing test or drilling pressure test is preferred, and the empirical formula is used to calculate the fracture pressure when the measured value cannot be obtained (Yang et al., 2021). However, weakly consolidated sandstone reservoirs generally feature poor cementation, low strength, relatively high porosity and high permeability. During the long-term water injection, a flow barrier may form due to large particles plugging on the wellbore wall, likewise, the formation permeability around the well may suffer damage due to fine particles plugging the pore channels, which can easily cause wellbore plugging and near-wellbore damage, resulting in a change in the near-wellbore formation pressure (Zhang et al., 2019). Meanwhile, most of the injection wells in offshore oilfields are mainly directional wells. Existing models for fracture pressure prediction have not covered the above-mentioned factors for directional injection wells in weakly consolidated sandstone.
Data Integration and Model Updating in a Multi-Stage Stimulation in the Bedretto Lab, Switzerland
Authors: Castilla R. , Serbeto F. , Christe F. , Meier P. , Bethmann F. , Alcolea A. , Dyer B. , Hertrich M. , Ma X.
Published: September 2022

A series of hydraulic stimulation treatments were performed in the Bedretto Underground Lab for Geosciences and Geoenergies (BULGG) between 2020 and 2021. The objective of this experiment was to prove that multi-stage stimulation is a suitable technology to improve the reservoir quality in granitic rocks. Classical hydraulic tests, mini-frac tests and shear stimulations were performed in different boreholes and at different intervals. Each one of these treatments yielded observations and data that allowed us to update the structural, hydraulic and geomechanics reservoir model and improve our understanding of the whole system.

Data resulting from the stimulation of one specific interval have been analyzed and integrated to build a coherent scenario. The integration of structural, hydraulic and geomechanical data is done using a Monte Carlo simulation allowing us to take into consideration the uncertainty inherent to each parameter. The comparison between theoretical results from the MC simulation and interpretations carried out on the data allow us to gain insights on the processes acting during the carried-out stimulation treatments.

1. BULGG CONFIGURATION

The Bedretto Lab for Geosciences and Geoenergies (BULGG) is located inside the Bedretto tunnel in the Canton of Ticino, Switzerland. Originally built as a service gallery during the construction of the Furka tunnel, a small section of the Bedretto tunnel has been repurposed by the ETH Zurich to build an underground laboratory. The main goal of the BULGG is to: "Study, in close collaboration with national and international partners, techniques and procedures for a safe, efficient, and sustainable use of geothermal heat".

The BULGG sits entirely inside the Rotondo Granite, a magmatic body that intruded Archean gneissic terrains during the Permian. For a comprehensive overview of the BULGG’s settings the reader can refer to Ma et al (2022).

As of beginning of 2022, a total of 16 boreholes have been drilled in the BULGG (Figure 1). The present work deals with data issued from a stimulation campaign carried out in 2020 in the ST2 borehole.
Optimization of CO2 Injector Location and Rate in Compartmentalized Reservoirs
Authors: Espinoza D. N. , Xu J. , Sun Z. , Balhoff M. T.
Published: September 2022

Carbon geological storage is a promising technology to divert massive amounts of carbon dioxide from local emission points and the atmosphere to subsurface reservoirs. Carbon storage projects seek maximizing injection rates and storage volumes. However, the injection of any fluid in the subsurface increases the reservoir pore pressure and alters the state of stress. Hence, maximizing injection rates and storage volumes face geomechanical limitations. This paper presents a method to optimize the selection of injector location and injection rates in faulted and fully compartmentalized reservoirs by integrating coupled reservoir and geomechanics simulations, cash flow, and neural networks. Injection stops when a fault approaches the shear yield limit at a distance fixed by a safety factor. We apply the method to a reservoir geometry inspired in a faulted sand in the Gulf of Mexico Coast. Low injection rates result in the highest storage volumes but in low net present value because of the long injection period (>100 years). Excessively high injection rates result in rapid changes of stresses in proximity to faults and early injection shut-in. The use of neural networks permits spanning all possible locations and injection rates and finding an optimum solution that maximizes net present value.

1. INTRODUCTION

CO2 storage in deep geologic formations is one solution to reduce CO2 emissions and CO2 atmospheric concentration (Bachu, 2008; Benson and Cole, 2008; Bickle, 2009). However, all pore space in geological formations is not readily available for storage since pore pressure increases due to injection can change the stress state and lead to fault reactivation – Fig. 1 (Cappa and Rutqvist, 2011; Faulkner et al., 2018; Tang et al., 2019; Ryu et al. 2019). Moreover, fault reactivation may induce seismic events or compromise fault sealing capacity (An et al., 2020; Rinaldi et al., 2015; Zoback and Gorelick, 2012). Compartmentalized reservoirs are more likely to develop high pressure increases with injection (Ehlig-Economides and Economides, 2013). Hence, pore pressure management is a critical activity in carbon geological storage for achieving high injection rates and volumes while averting geomechanical risks (Jung et al. 2019).
Measuring the Biot Coefficient for a Fluid-Saturated Crystalline Rock
Authors: Asem P. , Tarokh A. , Turos M. , Labuz J. F.
Published: September 2022

Biot coefficient α relates the increment of fluid content Δζ to an increment of bulk volume strain Δεv during the application of an increment of mean stress ΔP under drained conditions i.e. no change in cavity fluid pressure Δp = 0. The Biot coefficient α is measured as (i) the ratio of increment of fluid content to bulk volumetric strain α = Δζ/Δεv; (ii) the ratio of increment of mean stress to cavity fluid pressure α = ΔP/Δp under the conditions of zero volumetric strain; and (iii) (Equation), which requires the measurement of two other elastic coefficients, K = drained bulk modulus and (Equation) = unjacketed bulk modulus. Measurement of α using methods (i) and (ii) is challenging for crystalline rock. Hence, method (iii) is often promoted in the literature. The objective of this paper is to use methods (i), (ii), and (iii) to determine α at a Terzaghi effective mean pressure P′ = P − p = 15.0 MPa for Westerly blue granite, a typical crystalline rock. The specimen is saturated using the back pressure saturation approach, where a constant Skempton B-value at a specific Terzaghi effective mean pressure ensures full saturation. The experiments demonstrate that the three methods yield similar results for a at a given P′.

1. INTRODUCTION

A theory for deformation of a porous elastic solid containing a viscous compressible fluid was proposed by Biot (1935, 1941, 1956). Considering only volumetric response, with dynamic variables P and p and kinematic variables εv and ζ (Detournay and Cheng 1993), the constitutive relations are:

(Equation)

(Equation)

where εv = bulk volumetric strain, ζ = fluid content, P = mean stress, p = cavity fluid pressure, K = drained bulk modulus, B = Skempton cavity fluid pressure coefficient, and α = Biot coefficient.

In a jacketed test on a fluid-saturated specimen where Δp = 0, Biot and Willis (1957) showed the constitutive equations of poroelasticity yield three relationships for the elastic coefficient α:

(Equation)

(Equation)

(Equation)

where ΔVf = ΔVp = change in fluid volume contained within rock cavities under drained conditions, i.e. Δp = 0. Measurement of ΔVf requires calibration for system compliance involving careful evaluation of fluid exchange between the fluid-saturated rock and the reservoir. Under drained conditions, Eq. (3) is a representation of the ratio of cavity fluid volume change ΔVp to bulk volume change ΔV while Eq. (4) presents α as a measure of the competition between the change in mean stress ΔP and cavity fluid pressure change Δp to maintain zero bulk volumetric strain. The third interpretation of Biot coefficient α, i.e. Eq. (5), involves the measurement of two other poroelastic coefficients K and (Equation).
Prediction Model of Horizontal Drilling Limits and its Applications in Optimal Drilling Design
Authors: Wu Z. Q. , Huang W. J. , Yang J. , Jun Z.
Published: September 2022

Horizontal well is the key technology to effectively exploit oil and gas resources in beaches, mountains, lakes and offshore. However, there is a limit for the measured depth of horizontal drilling under the constraints of wellbore and equipment. Thus, the accurate prediction of drilling limits is of great significance for the design and operation of horizontal wells. In this paper, the prediction model of horizontal drilling limits is firstly built considering the constraints of hydraulic, mechanical and wellbore stability. Then, an optimal design method of horizontal drilling is proposed based on horizontal drilling limits. The case study shows that researches on horizontal drilling limits can provide important reference for optimization design and safe drilling.

1. INTRODUCTION

Horizontal well was risen in the 1920s (Zhang, 2015). Due to the limitation of technology and cost, horizontal well technology did not make a breakthrough at that time. With the progress of technology and the increase of experience, the cost of horizontal wells has been greatly reduced and the drilling period has been significantly shortened. As the contact area between horizontal well and reservoir is large, its production of oil and gas is high (Shi, 2013). Thus, it is widely used in the exploration and development of oil and gas.

At present, horizontal well technology has been relatively mature, and its measure depth continues to create new world records (Blikra, 1994; Sonowal, 2009; Gao, 2012; Samuel, 2013), especially in Wytch Farm Field (Allen, 1997; Tony, 2000), Sakhalin areas (Vishwas, 2014; Ganichev, 2016) and the Gulf of Mexico (Gao, 2019). For each horizontal well, there is a limit of its measure depth under specific constraints, which is called horizontal drilling limit. With the increase of vertical depth, horizontal drilling limit shows a trend of rapid increase - stability - linear decrease (Bakke, 2012). However, the constraints of each horizontal well are different, so it is difficult to accurately predict its horizontal drilling limit.
Poroelastic Stressing and Pressure Diffusion Along Faults Induced by Geological Carbon Dioxide Storage
Authors: Chang K. W. , Yoon H. , Martinez M. J.
Published: September 2022

Injecting CO2 into a deep geological formation (i.e., geological carbon storage, GCS) can induce earthquakes along preexisting faults in the earth’s upper crust. Seismic survey and regional geo-structure analysis are typically employed to map the faults prone to earthquakes prior to injection. However, earthquakes induced by fluid injection from other subsurface energy storage and recovery activities show that systematic evaluation of the potential of induced seismicity associated with GCS is necessary. This study mechanistically investigates how multiphysical interaction among injected CO2, preexisting pore fluids and rock matrix alters stress states on faults and which physical mechanisms can nucleate earthquakes along the faults. Increased injection pressure is needed to overcome capillary entry pressure of the fault zone, driven by the contrast of fluids’ wetting characteristics. Accumulated CO2 within the reservoir delays post shut-in reduction in pressure and stress fields along the fault that may enhance the potential for earthquake nucleation after terminating injection operations. Elastic energy generated by coupled processes transfers to low-permeability or hydraulically isolated basement faults, which can initiate slip of the faults. Our findings from generic studies suggest that geomechanical simulations integrated with multiphase flow system are essential to detect deformation-driven signals and mitigate potential seismic hazards associated with CO2 injection.

1. INTRODUCTION

Previous field demonstration projects revealed that detected seismicity is low magnitude and relatively small numbers [White & Foxall (2016)], suggesting that geological CO2 storage is unlikely to pose a seismic hazard. However, the amounts of injected CO2 have typically been small (less pressurization expected), and the lack of subsurface monitoring tools also limits the detection of seismic activities in spatial extent and/or temporal coverage [Nicol et. al. (2013)]. The successful storage of carbon dioxide (CO2) at commercial–scale, thus, requires evaluating potentials of the seismic hazard and its impacts on mechanical stability of the target formation [Verdon et al. (2013), Rinaldi et al. (2014), Dempsey et al. (2014)].
Modelling Slugging Induced Flow Instabilities and its Effect on Hydraulic Fractures Integrity in Long Horizontal Wells
Authors: Khetib Youcef , Rasouli Vamegh , Rabiei Minou , Chellal Hichem Aymene Katib , Abes Abdelmalek , Bakelli Omar , Aoun Ala Eddine
Published: September 2022

Unconventional reservoirs are developed by drilling long horizontal wells of up to 20,000 ft laterals and produced using multistage hydraulic fracturing (HF) operations. The production profile of such wells has a steep decline at early life (3 to 12 months) during which the flow rates decrease with a diminishing bottom hole pressure and the flow starts oscillating at an increasing amplitude. After reaching the bubble point value, the gas starts releasing at the lateral section and slugs start to form, merge and travel through the vertical section before reaching the wellhead. This flow instability affects the downhole pressures with large variations, reaching several hundreds of psi at the sand face part. The pressure variations have an impact on the hydraulic fracture’s integrity and need to be considered for the safety operations envelop (SOE). In this study the effects of pressure variations have been studied by integrating the transient multiphase flow simulation results of the Bakken well LINSETH 13-12HWinto a dynamic 3D reservoir and geomechanical model. Mid-life production performances were considered to capture the flow and pressure oscillation at their maximum rates. Using the reservoir model, the pressures, and saturations were calculated at different time steps. Also, the geomechanical model was built and calibrated using core data. The model was used to evaluate potential proppant dis-embedment which may lead to proppant settlement at the lower part of the fractures and closes the upper part, resulting in reduced productivity, and contributing to further production decline. The result of this study is used for improved production management of unconventional plays and extended-reach wells.

1. INTRODUCTION

Unconventional wells are characterized by a steep initial decline, of flow rates, and pressures during the first 1 to 12 months, requiring operating companies to pre-install artificial lift equipment, usually a mix of Gas lift, ESPs, HJP, and Rod Pumps are used in North Dakota.
Simulation of Drilling Challenges in Pressurized Saltwater Disposal: A Case Study in the Williston Basin
Authors: Khetib Youcef , Rasouli Vamegh , Rabiei Minou , Chellal Hichem Aymene Katib , Abes Abdelmalek , Bakelli Omar , Aoun Ala Eddine
Published: September 2022

Water is produced along with the hydrocarbons from the Bakken and Three Forks formations in the Williston Basin. The water to oil ratio increases over time, with more water being produced as the formation is depleted further. Water needs to be managed, treated, and disposed of for production to continue. Salt water disposal into porous formations is a common practice in the Bakken, which is regulated for proper water injection and disposal. Studying the effect of the water injection and its impact on saturation/salinity, and change of formation pressure and in-situ stresses over time are some of the important aspects to be considered. This study investigated the effect of pressure increase around the saltwater disposal wells due to water injection. A total of 115 saltwater disposal wells were used in this study to model the Inyan Kara aquifer formation in the Bakken. The dynamic flow and 1D geomechanical models were built based on injection tests, build-ups interpretations, and historical injections rates in order to capture the historical performances of the aquifer over time. The aquifer pressure evolution over time was investigated at the location of current producing wells and at future potential drilling locations to reach the Middle Bakken and Three Forks reservoir formations. The results showed that the elevated pressure of the aquifer requires substantial increases of the mud weight to avoid shear breakouts and fracturing of the formation, which increases the risk of fracturing the Skull Creek formation above and Swift formation below the Inyan Kara. Also, the salinity difference is expected to cause barium sulfate and calcium carbonate precipitation and injectivity issues. No casing failure is expected for the cases that studied here as the pressure will not exceed the casing strength.

1. INTRODUCTION

Hydrocarbons production is predominately associated with water production. Formation water is separated treated and disposed. The unconventional resources development in the Williston Basin was accompanied by a large amount of produced water. The amount of water is the same as the volume of produced oil. The produced water is then disposed through a network of salt water disposal wells, which are completed through the Dakota Group of formations mainly targeting the Inyan Kara formation.
Prediction Method on Fatigue Life of Drill String with Initial Defects in Extended-Reach Drilling
Authors: Fan Baitao , Huang Wenjun , Wu Zhiqiang , Shi Xiaolei , Ren Chuanjie
Published: September 2022

Numerous studies have shown that approximately 50% of drill string failure modes are fatigue failure, and the initial defects in the drill string are one of the key factors affecting the fatigue life of the drill string. The influence of initial defects is often ignored in traditional fatigue life prediction model of drill strings, which leads to high prediction results of drill string life and underestimation of drill string failure risks. In this paper, considering the stress intensity factor, stress amplitude and crack geometry a method for predicting the fatigue life of drill string with and without initial defects in the whole section of extended reach well is established. Finally, the new model is applied used to for a case study, and the average stress and fatigue life of drill strings with and without initial defects under different defect depths, crack sizes, rotating speeds and weight on bit are calculated and compared. The results show that the fatigue life of drill string mainly depends on the defect depth and crack size. The larger the initial defect depth and crack size, the faster the fatigue life of drill string decreases. Weight on bit and rotating speed are secondary factors. With the increase of WOB and rotating speed, the stress intensity factor increases, the crack propagation rate increases, and the fatigue life of drill string decreases. The position of minimum fatigue life may be different under different parameters. The two minimum fatigue life positions predicted in this paper are 3188m and 4509m, respectively, which are weak points of fatigue life. The research results have important guiding significance for the optimization design and drilling safety control of extended reach wells.

1. INTRODUCTION

With the needs of oil and gas exploration and development, the design of drilling wells has gradually changed from a single model such as vertical wells to complex structural models such as extended-reach wells and long horizontal wells. Compared with vertical wells, the horizontal section of complex structure wells increases, and problems such as high friction torque, frequent backing pressure, and buckling of pipe strings are more serious. Due to its own motion and downhole loads, drill strings often fail prematurely, which seriously affects the service life of the drill pipe and brings great risks and serious challenges to drilling and completion operations. Therefore, it is necessary to use mechanical methods to analyze the failure of the drilling tools and predict the fatigue life of the drill string, so as to better prevent and reduce the downhole fracture accidents of the drill string.
Sediment Stress in an Extensional Basin with Pre-Existing Fault and Salt Roller
Authors: Nikolinakou M. A. , Heidari M. , Hudec M. R. , Flemings P. B.
Published: September 2022

We study sediment stress in an extensional basin with a critically oriented pre-existing fault and an underlying salt layer using forward geomechanical models. We first identify stress changes in a basin without salt. We show that the presence of a fault with lower frictional resistance than the intact sediment leads to re-orientation of principal stresses near the fault, and abrupt changes in the minimum principal stress across the fault. Sediment rollover in the hanging wall leads to stress arching, which reorients principal stresses in the upper parts of the hanging wall despite the ongoing extension. When salt underlies the sediment basin, a salt roller develops at the location of the fault and minimizes sediment rollover in the hanging wall. Loading from the rising diapir increases horizontal stress in the hanging wall. The angled salt face also transmits higher overburden stresses from deeper parts of the basin to the shallow footwall area and loads the footwall sediments. We built these transient evolutionary simulations with Elfen. We model salt as solid viscoplastic and model sediments as poro-elastoplastic material.

1. INTRODUCTION

Several numerical studies have explored the geomechanical interaction between salt and its wall-rock sediments (see Nikolinakou et al. (2018) for a review). These studies couple salt flow with sediment deformation and, in transient analyses, porous fluid flow. However, they model sediments as a continuum.

A large number of salt basins are located in extensional systems (rift basins, passive margins; e.g., Jackson and Hudec (2017)). Normal faults are key features in these extensional systems. Faults are often weak discontinuities: their frictional strength is lower than that of continuum sediments. They can alter the in-situ stress state, sediment porosity, and strength (e.g., Schultz (2019)). Consequently, they may affect the salt flow and evolution of the salt geometry.

Here, we study a simple extensional basin with a pre-existing fault and an underlying salt layer. We use a large-strain, evolutionary model to simulate the regional extension, the development of a salt diapir, and the deformation along the critically oriented fault. We first identify stress changes in a basin without salt. Then, we study how the presence of a reactive diapir affects the stress state in both hanging wall and footwall.
Undrained Creep Response of Shale: Argon vs. scCO2
Authors: Kamali-Asl A. , Hashemi S. S. , Kovscek A. R. , Zoback M. D.
Published: September 2022

We used core samples from the Wolfcamp formation in the Permian Basin to conduct creep experiments with argon and scCO2 as the pore fluids. We conducted the tests at a temperature of ~ 42 °C, confining pressures of 40 and 70 MPa, pore pressures of 10 MPa, and various levels of differential stress. Creep stages lasted for either 24 or 48 hours and prior to creep the Young’s modulus was estimated based on the loading history. When CO2 results are compared to the argon results, the Young’s modulus of the carbonate-rich sample increases, while the Young’s modulus of the clay-rich sample decreases. The viscoplastic response with scCO2 as the pore fluid generally indicates more significant deformation. This is attributed to the aggregate effects of carbonate dissolution and swelling strain of clays and kerogen. A power-law model has been implemented to predict the longer-term creep response of the samples. The fitting parameters are satisfactory; however, additional investigation is needed for the scCO2 case, due to time-dependent chemical interactions with the sample.

1. INTRODUCTION

Geological storage of carbon dioxide (GCS) is one of the relatively short-term feasible solutions to climate change (Bouckaert et al., 2021). While the storage of CO2 is likely to occur in a porous sandstone reservoir, the target formation needs to be sealed by a low permeability caprock such as shale. Employing CO2 as the stimulation fluid of unconventional reservoirs is another method of sequestering carbon dioxide into the subsurface. In both applications, the shale formation is exposed to CO2 over prolonged periods of time. Therefore, it is necessary to investigate the alterations in the mechanical/transport characteristics of shale reservoirs when they are exposed/interacted to/with CO2.

Shales typically possess ultra-low permeabilities (usually below 1 μD) with very complex micro-structure, and is mainly composed of quartz, carbonates, clays, and organic matter (Zoback and Kohli, 2019). Interaction between shales and carbon dioxide in the presence of in-situ water results in (i) adsorption-induced swelling of clays and organic matter, (ii) dissolution of carbonate minerals due to interaction with carbonic acid, and (iii) mineral/salt precipitation (Linder et al., 2016; Kamali-Asl et al., 2021). Some past research has been dedicated to the changes in the micro-structure of shales as they are exposed to dry CO2 or CO2-saturated brine (Sanguinito et al., 2018; Hadian and Rezaee, 2020), while others have focused on changes of porosity/permeability (Wu et al., 2017; van Noort and Yarushina, 2019).
Numerical Analysis of Interaction Between Hydraulic Fracture and a 3D Spherical Cave
Authors: Kao Jiawei , Xu Dan , Bian Xiaobing , Yin Shize , Jin Yan
Published: September 2022

The matrix is dense for deep cavernous carbonate reservoirs in Tarim Basin, and oil and gas are mainly enriched in caves. We hope that hydraulic fractures can communicate with more caves. However, the existence of caves will disturb the stress field and influence hydraulic fracture propagation. Thus, the interaction between hydraulic fractures and caves and whether they can penetrate caves has a significant impact on the fracturing efficiency of cavernous formation, which is worth studying.

This paper studied the interaction rule between hydraulic fracture and a 3D single cave by discontinuous discrete fracture model (DDFM). In this model, the cave was set as a three-dimensional sphere with fluid in it, which is located in the maximum horizontal stress direction along one side of the vertical well. The initial hydraulic fracture is perpendicular to the direction of minimum horizontal stress. The fluid-solid couple action, fluid flow, and mass transfer during fracturing were considered. By means of the control variable method, we analyzed the intersection characteristic between hydraulic fracture and a cave and whether it could be penetrated.

The results show that when hydraulic fracture approached close to a cave, it expanded to the side of the cave preferentially due to an attraction action. After they intersected, hydraulic fracture turned to expand along height direction at the intersection to break the cave wall because of stress concentration. However, they encountered resistance when hydraulic fracture opened most of the cave wall and tried to penetrate. Under limited injection volume conditions, whether hydraulic fracture can penetrate and continue to expand was related to cave diameter, in-situ stress, the distance between the cave and well, filtration coefficient, and injection rate.

This paper revealed the propagation characteristics and morphology of hydraulic fracture interacting with a 3D cave, which could help understand the interaction between hydraulic fracture and a 3D cave and provided a reference for optimizing the fracturing parameters of cavernous carbonate reservoirs.
Permeability of Water-Rich Sandstone Experienced One Freeze-Thaw Process Under Different Confining Pressures
Authors: Liu Bo , Yang Shuo , Zhang Jingtao , Han Yanhui , Sun Yanding , Zhang Xianxin , Liu Nian
Published: September 2022

During the construction of mine shafts in Northwest China, the rock mass in frozen wall experiences a full cycle of freeze-thaw loading process, which will lead to the change of porosity and permeability of rock mass. Due to the lack of in-depth understanding of the permeability of rock mass after thawing, water penetration and shaft flooding accidents have occurred frequently. In this study, the permeability characteristics of sandstone samples without freezing-thawing and experienced one freeze-thaw cycle under different confining pressures were investigated. The effects of the confining pressure in the freeze-thaw loading process (referred to as freeze-thaw stress), osmotic pressure and effective confining stress (i.e. the confining pressure minus osmotic pressure) on the permeability of the sample were also analyzed. The results indicated that the permeability of the sample increased along with the osmotic pressure when the osmotic pressure was less than 5 MPa. However, when the osmotic pressure was greater than 5 MPa, the permeability tended to be stable as the osmotic pressure increased, and decreased slightly for some samples. The permeability of sandstone samples undergoing freeze-thaw process decreased with the increase of effective confining stress. When the osmotic pressure was constant, the permeability increased linearly with freeze-thaw stress. CT test results showed that the porosity increased after freeze-thaw test, resulting in an increase of permeability with the increase of freeze-thaw stress. The experimental results are helpful for the pre-control of water intrusion related disasters occurring after the thawing of the frozen wall.

1. INTRODUCTION

Mine shaft construction in Northwest China mainly cuts through the Jurassic and Cretaceous strata characterized as weakly cemented and water-rich strata. Artificial freezing is the main effective technology to excavate the deep water-rich strata in mining. However, due to the lack of understanding of the permeability characteristics of the frozen wall after thawing, water penetration and shaft flooding accidents have occurred frequently. (Zheng et al., 2011; Deng et al., 2010).
The LOP Revisited
Authors: Raaen A. M. , Andrews J. S. , Fintland T. G.
Published: September 2022

The Extended leak-off test, XLOT, is a main tool for obtaining minimum stress data during drilling operations. If performed according to a proper protocol, it is perhaps the most cost-effective and robust method for determining the minimum stress. The low cost of the test means that a lot of data can be collected, allowing for efficient regional analysis. A widely reproduced figure by Gaarenstrom et al. (1993) has become a classic in the industry. It shows the pump-in phase as two distinct linear segments. The point of change in slope is denoted the Leak-off Point or the Leak-off Pressure (LOP). It is sometimes argued that the LOP is a good measure of the in-situ stress, and it is sometimes argued the LOP marks the initiation of a fracture. We analyze this hypothesis and show by basic theoretical considerations and several examples of high quality field data that this is not necessarily the case. The nonlinear behavior during initial pump-in may be due to leak-off to a permeable formation or through a poorly cemented casing shoe.

1. INTRODUCTION

The importance of knowing the in-situ stress has been realized for a long time in the petroleum industry, see e.g., Hubbert and Willis (1957), Fairhurst (1965), Haimson and Fairhurst (1967), Nolte and Smith (1981), and many others.

The minimum stress is of direct use in hydraulic fracturing, where proper stress data are essential for the design of a successful job. Therefore, most conventional fracturing jobs are preceded with datafracs or minifracs, aiming to determine the parameters for designing the main job, with the minimum horizontal stress being of central importance in addition to calibrating fluid leak-off behavior during fracture propagation. More recently the Diagnostic Fracture Injection Test has gained prominence in very tight and unconventional plays where it is possible to estimate the same main parameters but also analyze for pore pressure and permeability.
Research and Application of Integrated Technology of Chemical Sand Control and Stratified Water Injection in Offshore Oilfields Injection Well
Authors: Shunchao Zhao , Yugang Zhou , Huaxiao Wu , Baobing Shang , Tao Fang , Huaxing Chen , Yufei Wang , Yadong Qi , Ming Pang
Published: September 2022

This paper proposes an integrated technology of chemical sand control and stratified water injection in water injection well, which enlarge the inner diameter of injection well and achieve flexible stratification. The technology realizes completion by chemical sand control. The ceramsite whose surface has been treated by crosslinking agent is injected into the well and form a cement layer with a thickness of 3-5 cm. This layer can be used as a barrier to retain sand and provide channels for fluids. Then, the stratified injection string is run to realize the stratification of the injection reservoir. The position and quantity of the stratification are designed can adjust flexibly. This technology has been successfully applied in the Bohai Oilfield. The conventional sand control and injection technology makes it difficult for the actual injection rate to reach the target value. After applying the integrated technology, for a directional well with a bore diameter of 9.625 in, the maximum inner diameter can reach 7 in. The number of injection layers exceeds 5, and the actual injection volume meets the designed rate. Besides, the water cut of the beneficiary well decreases, and the oil production rate increases.

1. INTRODUCTION

Stratified water injection is an important measure to improve the overall oil recovery, and it is very important to achieve sufficient water injection in the target reservoir. The sand control method of water injection wells in offshore oilfields is mainly mechanical sand control. The plug-in seal on the water injection pipe cooperates with the sealing cylinder to realize stratified water injection, which the number of layers is generally 3-4. For reservoirs with strong vertical heterogeneity, there may be problems such as large differences in water absorption profiles in the same injection layer, small longitudinal sweep coefficient of water flooding, and overall water injection rate that does not meet the design requirements. It is difficult to change the number and the location of layers, and it is impossible to adjust the layers according to the water injection system. In addition, the inner diameter of mechanical sand control is small, and the downhole testing and other operations are difficult, which also limits the injection rate.
A Prediction Model of Casing Exterior Wear During Casing Running
Authors: Zhou Yuting , Zhang Hui , Li Jun , Lu Zongyu , Shi Jiangang
Published: September 2022

In the process of exploration and development of extended-reach wells and ultra-deep wells, serious dogleg severity and high hardness formation, etc. will lead to casing exterior wear, thereby reducing the residual strength of the casing. However, the existing research on casing wear mainly studies the interior wear of casing caused by the rotation of drill pipe joints, and ignores the exterior wear caused by the contact between casing and well wall during casing running. As a consequence, the prediction model of casing exterior wear is established based on the wear efficiency model and the three-dimensional torque and drag model. Case study is conducted with this model and sensitivity analysis is also performed. The results show that the casing with the greatest exterior wear depth is located below the direction turning section. The wear depth decreases with the increase of the outer radius of the casing, and increases with the increase of the wellbore radius. In addition, with the increase of drilling fluid density, the wear depth of the upper casing increases, and the wear depth of the lower casing decreases. The casing collapse resistance after casing exterior wear is studied through numerical simulation. The results show that the collapse resistance of casing decreases with the increase of wear depth, and there is an approximate linear relationship between the two. The study provides a method to improve the prediction accuracy of casing wear, which is of great significance for the casing design and wellbore integrity.

1. INTRODUCTION

With the development of drilling technology, horizontal well and extended reach technologies are widely used in the world. The wellbore conditions of extended-reach wells and horizontal wells with long horizontal sections are more complicated than conventional wells. Running casing is challenging due to the difficulty of hole cleaning, the high friction factor, the wellbore tortuosity, and the large lateral force acting on the wellbore by the casing, etc. Usually the casing needs to be picked-up and released many times, and the running time is long, so the outer wall of the casing is more likely to be worn, which reduces the residual strength of the casing.
Experimental Study on High-Strength Resin Wellbore Annulus Plugging Technology of Underground Gas Storage Facilities
Authors: Leng Guangyao , Yan Wei , Ge Hongkui , Deng Jingen , Nguu Dickson Muchiri , Tan Rui , Han Yue , Li Zhong
Published: September 2022

Underground gas storage is characterized by large gas injection and withdrawal cycles, making the wellbore bear repeated loading and unloading. Subjecting cement sheath to these conditions can cause damage, thus compromising its ability to provide complete zonal isolation. Wellbore annulus plugging with high-strength resin technology was studied to evaluate its effectiveness in controlling unwanted fluid migration through triaxial mechanical properties test, corrosion inhibiting ability test, and anti-gas channeling performance evaluation. The experimental results showed that the curing time was extended by 1.9 hrs by doubling the amount of diluent. At the same time, doubling the amount of the curing agent increased the compressive strength by 5.3 MPa. Under the triaxial test conditions, the four resin materials exhibited high compressive strength, low elastic modulus, and low Poisson’s ratio. Injection of corrosive CO2 at 0.5 MPa, reduced the compressive strength of the four resins within the range of 4.9% ~24.3%. A 100g of epoxy resin mixed with 10 g of diluent and 20 g of the curing agent significantly reduced the curing time. In addition, this mixture increased the maximum differential stress, and elastic modulus to 100.5 MPa and 3.325 GPa, respectively, after 1.6 h. The gas test anti-channeling pressure of the 5 cm sample was as high as 19.1 MPa. The test samples maintained long-term stability under continuous high pressure and tightness under the action of the alternating load of a significant pressure difference. This study uses high-strength plugging gel technology to provide a technical guide for wellbore remedial redress and plugging in underground gas storage.

1. INTRODUCTION

The formation is effectively sealed with cement to prevent cross-flow under differential pressure and ensure smooth oil and gas production (Jordan et al., 2015; De et al., 2017; Hatambeigi et al., 2020; Valov et al., 2022). Cement has the disadvantages of high brittleness, poor corrosion resistance, and insufficient durability. Under the action of alternating load, micro-cracks and micro-annulus can easily be generated on the wellbore system. In addition, the presence of an acidic medium such as CO2 can cause the cement barrier to corrode, further compromising its ability to prevent unwanted fluid migration.