bluuebunny/crossref_metadata_2025_split huggingface dataset:
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

ABSTRACT:
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

ABSTRACT:
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

ABSTRACT:
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 (&gt;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

ABSTRACT:
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

ABSTRACT:
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

ABSTRACT:
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

ABSTRACT:
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

ABSTRACT:
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

ABSTRACT:
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.