bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Machine-Learning Based Workflow for Predicting Overpressure in a Stiff Dolomitic Formation
Authors: Nivlet Philippe , Yang Yunlai , Magana-Mora Arturo , Abughaban Mahmoud , Abegunde Ayodeji 
Published: December 2021

Abstract
Overpressure refers to the abnormally high subsurface pressure that may exceed hydrostatic pressure at a given depth. Its characterization is an important part of subsurface characterization as it allows to complete drilling operations in a safe and optimal way. In dolomitic formations, however, the prediction of such overpressure is especially challenging because of (1) the high degree of lateral variability of the formations, (2) the limited effect of overpressure on tight rocks elastic parameters, and (3) the complexity of physical processes involved to form overpressure. In addition to these factors, existing experimental models generally used to relate elastic parameters to pressure are often not well calibrated to carbonate rocks. The alternative to existing purely physical approaches is a data-driven model that leverages data from offset wells. We show that due to the complexity of the characterization question to be solved, an end-to-end machine learning based approach is deemed to fail. Instead of a fully automated approach, we show a semi-supervised workflow that integrates seismic, geological data, and overpressure observations from previously drilled wells to map overpressure regions. Attribute maps are first extracted from a 3D seismic data set in an overpressured geological formation of interest. An auto-encoder is then used to learn a more compact representation of data, resulting in a reduced number of latent attributes. Then, a hand-tailored semi-supervised approach is applied, which is a combination of clustering method (here based on DBSCAN algorithm) and Bayesian classification to determine overpressure risk degree (no risk, mild, or high risk). The approach described in this study is compared to direct end-to-end models and significantly outperforms them with an error on a blind well prediction of around 25%. The overpressure probability maps resulting from the models can be used later for the optimization of drilling processes and to reduce drilling hazards.
An Experimental Investigation of the Effect of Changing the Rock's Wettability on the Performance of Carbonated Water Injection CWI
Authors: Castaneda Jaime Orlando , Alhashboul Almohannad , Farzaneh Amir , Sohrabi Mehran 
Published: December 2021

Abstract
CWI is affected by multiple factors, including the wettability of the rock. These experiments seek to determine the results that are obtained when CW is injected in a tertiary mode for systems: (1) wetted by water and (2) mixed wettability; to date, no study has used this approach. The same sandstone core was used in all trials, and each test consisted of saturating the core with live crude, followed by the injection of water as a secondary recovery and then the injection of CW as a tertiary recovery. An additional sensitivity test was conducted that consisted of varying the composition of the dissolved gas in the crude. In general, in a water wet system, the recovery associated with the injection of CW is higher (normalized) compared to a mixed wettability system. This does not mean that the results were negative in the mixed system. On the contrary, the results are positive since on the order of an additional 20% was recovered. However, the pressure differential in a mixed system is higher (14%) compared to water wet system. Although it is common knowledge that wettability of the rock affects the production and pressure results in an experiment, these are the first experiments that have been performed exclusively to determine quantitatively the response to CWI while maintaining the other parameters constant.
Novel CO2/N2 Foam Concept and Optimization Scheme for Improving CO2-foam EOR Process
Authors: Gajbhiye Rahul 
Published: December 2021

Abstract
Nitrogen and Carbon dioxide are the most common gases utilized in enhanced oil recovery (EOR) techniques. Most of the gas injection process suffers from the gravity override and viscous fingering resulting in lower oil recovery. Foam is introduced in enhanced oil recovery (EOR) to mitigate these problems encountered during gas flooding. When it comes to the CO2-gas injection the CO2-becomes supercritical at a typical reservoir condition giving it difficulty to form CO2-foam at reservoir condition. The CO2-foam has a common problem to become weaker above its supercritical conditions of 1100 psi and 31°C. As a result, the advantages of using CO2 foam are diminished due to the weakness of CO2-foam at supercritical conditions and results in a lower recovery.
However, CO2-foam can be generated by replacing a portion of CO2 with N2 gas. It lacks the understating of mixture properties and its effect on EOR. This study evaluates the performance of CO2/N2 foam at supercritical conditions for EOR. It aims to improve recovery under supercritical conditions by using N2/CO2 mixture foam and optimize the foam quality and CO2/N2 ratio.
The results from the experiments showed that the CO2/N2 foam flooding recovered an additional oil of Original Initial Oil in Place (OIIP) indicating that foam flooding succeeded in producing more oil than pure CO2-foam injection processes. Also, the results of foam flooding at different foam quality and CO2/N2 ratio significantly affected the performance and recovery of the process. Hence it is necessary to optimize the CO2/N2 foam parameters flooding process which is affected by the parameters such as foam quality and CO2/N2 ratio. The study also shows an experimental approach for optimizing CO2/N2 foam parameters.
The concept of adding N2 to CO2 is a novel way of generating CO2 foam at supercritical conditions. Although investigators are trying different ways to generate the strong and stable CO2- foam, adding N2 to CO2 can be considered to be the easiest way for foam generation as CO2 is always having some impurities in the form of other gases and N2 can be considered as one of such gas helps in generating the foam.
Interwell Saturation Prediction by Artificial Intelligence Analysis of Well Logs
Authors: Kovalev Dmitry , Safonov Sergey , Katterbauer Klemens , Marsala Alberto 
Published: December 2021

Abstract
Well log analysis, through deploying advanced artificial intelligence (AI) algorithms, is key for wellbore geological studies. By analyzing different well characteristics with modern AI tools it becomes possible to estimate interwell saturation with improved accuracy, outlining primary fluid channels and saturation propagations in the reservoirs interwell region. The development of modern deep learning and artificial intelligence methods allows analysts to predict interwell saturation as a function of observed data in the near wellbore logged geological layers. This work addresses the use of deep neural network architectures as well as tensor regression models for predicting interwell saturation from other well characteristics, such as resistivity and porosity, as well as local near-well saturation. Several algorithms are compared in terms of both accuracy and computational efficiency. Sensitivity analysis for model parameters is carried out, which is based on the wells’ geometry, radius, and multiple sampling techniques. Additionally, the impact of local saturation prior knowledge on the model accuracy is analyzed. A reservoir box model encompassing volumetric interwell porosity, resistivity and saturation data was utilized for the validating and testing of the AI algorithms. A prototype is developed with Python 3.6 programming language.
The Impacts of Increased Ductility in Organic-Rich Shale on Fracture Network Growth by Hydraulic Fracturing
Authors: Huang Chang , Chen Shengli 
Published: December 2021

Abstract
The difficulty of hydraulic fracturing in organic-rich shale caused by the increased ductility has not been well interpreted quantitatively, although it is well perceived that the increased shale ductility can impede the propagation of hydraulic fractures and enhance the healing of created fractures upon injection shutdown. This study aims to quantitatively study the impacts of increased ductility on the stimulated reservoir volume (SRV) using an advanced XFEM-based simulator.
To achieve this goal, a modified cohesive zone model has been integrated into an in-house fully coupled poroelastic XFEM framework. The study continues by extending the functionality of the numerical framework to simulating multiple interacting fractures. The utilization of the object-oriented programming paradigm in the development of the framework makes it an easy extension to include the multi-fracture network by creating more instances of crack segments. A main hydraulic fracture with an arbitrary number of intersected branches can thus be modeled. A series of parametric studies will be conducted to investigate the impacts of increased ductility on the induced SRV by varying four involved material parameters individually.
The modified cohesive zone model, which is essentially a traction-separation law (TSL), is characterized by four parameters: the initial tensile strength Tini, ultimate tensile strength Tkrg, the critical separation Dc, and the final crack separation Dmax. It can flexibly model different crack opening scenarios and simulate more realistically the increased shale ductility. The fully coupled poroelastic XFEM framework has been comprehensively verified against the latest semi-analytical solutions on the four well-known propagation regimes. The numerical results show that the shape of TSL does affect the main hydraulic fracture growth as well as the evolvement of the fracture network, given the same cohesive crack energy and tensile strength. It infers that ductility is not only controlled by cohesive crack energy and tensile strength, which further indicates the necessity of the newly proposed cohesive zone model. The magnitude of the initial tensile strength, controlling when the cohesive crack starts propagating, is found to have the greatest impacts on the fracture length, and SRV, among all four TSL parameters.
The novelty of this study is two-fold. First, the newly modified cohesive zone model can more realistically represent the increased shale ductility. Second, the advanced XFEM framework that enables the simulation of a fracture network can study the impacts of increased ductility on the whole SRV but not a single crack.
Wellbore Stability Beyond Mud Weight
Authors: Khan Khaqan , Altwaijri Mohammad , Ahmed Sajjad 
Published: December 2021

Abstract
Drilling oil and gas wells with stable and good quality wellbores is essential to minimize drilling difficulties, acquire reliable openhole logs data, run completions and ensure well integrity during stimulation. Stress-induced compressive rock failure leading to enlarged wellbore is a common form of wellbore instability especially in tectonic stress regime. For a particular well trajectory, wellbore stability is generally considered a result of an interplay between drilling mud density (i.e., mud weight) and subsurface geomechanical parameters including in-situ earth stresses, formation pore pressure and rock strength properties. While role of mud system and chemistry can also be important for water sensitive formations, mud weight is always a fundamental component of wellbore stability analysis. Hence, when a wellbore is unstable (over-gauge), it is believed that effective mud support was insufficient to counter stress concentration around wellbore wall. Therefore, increasing mud weight based on model validation and calibration using offset wells data is a common approach to keep wellbore stable.
However, a limited number of research articles show that wellbore stability is a more complex phenomenon affected not only by geomechanics but also strongly influenced by downhole forces exerted by drillstring vibrations and high mud flow rates. Authors of this paper also observed that some wells drilled with higher mud weight exhibit more unstable wellbore in comparison with offset wells which contradicts the conventional approach of linking wellbore stability to stresses and rock strength properties alone. Therefore, the objective of this paper is to analyze wellbore stability considering both geomechanical and drilling parameters to explain observed anomalous wellbore enlargements in two vertical wells drilled in the same field and reservoir.
The analysis showed that the well drilled with 18% higher mud weight compared with its offset well and yet showing more unstable wellbore was, in fact, drilled with more aggressive drilling parameters. The aggressive drilling parameters induce additional mechanical disturbance to the wellbore wall causing more severe wellbore enlargements. We devised a new approach of wellbore stability management using two-pronged strategy. It focuses on designing an optimum weight design using geomechanics to address stress-induced wellbore failure together with specifying safe limits of drilling parameters to minimize wellbore damage due to excessive downhole drillstring vibrations. The findings helped achieve more stable wellbore in subsequent wells with hole condition meeting logging and completion requirements as well as avoiding drilling problems.
Unique 15kpsi Multistage Fracturing Liner System Delivers Solution to Overcome Tight Formation Challenges
Authors: Wright Beau R , Khan Parvez 
Published: December 2021

Abstract
Open hole Multistage Fracturing (MSF) systems have been deployed for treating open hole formations with multiple, high rate hydraulic fracturing stages while gaining efficiency during pumping operations unlike traditional plug-and-perf operations. One important challenge within the industry was availability of an open hole packer system that can overcome tough wellbore conditions during deployment and function as designed during the high rate high pressure stimulation operations. This paper will discuss the successful planning and deployment of one such system.
For successful deployment of any open hole fracturing completion, one must first consider the environment that the system will be deployed into. Lateral length, open hole size, parent casing size and tubing stresses during fracturing and production all inclusively influence the need for a robust and reliable system. Other several important considerations to be deployed as a liner is the compatibility of the completion tools with the Liner deployment system, the robustness of being deployed into challenging open hole conditions where capability of high circulating rates and rotation become mandatory to get the bottom hole assembly (BHA) to its final setting depth. Last but not least, in order to achieve successful stimulation, each component of the system after overcoming all the deployment obstacles should function as designed withstanding treating differentials as high as 15kpsi, while simultaneously accommodating induced axial loads caused by these high-pressure treatments.
The development and testing of individual components of the system was done keeping in mind wellbore instability and obstacles the completion will have to overcome during deployment. The field execution was planned with close collaboration with the operator and other key services that were involved for drilling the well. Real-time monitoring of the well allowed for simultaneous swift implementation of changes required on tool activation pressures, identification of hazards and mitigation plan to overcome challenges in order to execute the job successfully.
It is worth mentioning that the successful deployment of this system represents the first use of additive manufacturing in high pressure, hydraulic set open hole packers. This technology allowed overcoming the barriers of challenges associated with deploying open hole completion in tight challenging formations that would otherwise have limited deployment capabilities.
Remote Activated Completion Technology Enhances Operational Efficiency of Offshore Wells in Middle East
Authors: Keerthivasan Vijay Kumar , Young Dustin , Mehus Cathrine , Gjedrem Bjornar , Abdelghany Moetaz , Khov Henry 
Published: December 2021

Abstract
To access a larger amount of pay zone, well trajectories are becoming longer and more complex, creating greater challenges for running completion liners. A liner shoe is a casing accessory tool that aids in the running of completion liners in long wells by allowing auto-filling of the liner and enabling pumping through the bottom of the liner. Upon reaching planned liner depth, the liner shoe is closed to allow for pressure testing and subsequent completion operations. Conventional methods used to close a liner shoe involve well intervention to set plugs or by dropping a ball, and there are inherent costs and risks associated with these operations. This paper presents the development and deployment of a remotely activated electronic liner shoe (ELS) for offshore applications that enables interventionless closing of the liner shoe, thereby improving operational efficiency, and reducing potential operational issues that could occur while closing the liner shoe conventionally. The ELS allows the operator to precisely control when the liner shoe closes – either based on pre-programmed pressure signals, a timer, or a combination of the two. A major operator in the Middle East required an ELS to be developed and qualified specifically for their offshore well conditions. A new technology qualification program was devised in collaboration with the operator to qualify both the electronic and mechanical functionalities of the tool.
This paper documents the methods and results of the extensive qualification test program. The development and qualification process were successfully completed within 10 months at research and development facilities in Norway. Following qualification testing, the ELS was first deployed for the operator in an offshore well in Q4 of 2019. Operational considerations in programming the remote functionality of the tool is presented in this paper. After a successful field trial, the ELS has been run in more than 15 offshore wells and has become the standard option in the operator's completion program.
New Steering Technology Using Pulsed Arc Plasma Shockwave: Plasma Pulse Steering Technology
Authors: Liu Kerou , Zhang Hui , Xie Renjun , Wu Yi , Jiao Jingang , Cai Zhixiang , Fu Hao 
Published: December 2021

Abstract
Steering drilling technology can achieve precise control of wellbore trajectory, and related technologies have been widely used in the field of petroleum drilling. This paper proposed a new steering drilling technology based on the Pulsed Arc Plasma Shockwave Technology (PAPST),Plasma Pulse Steering Technology (PPST).
PAPST transforms electric energy into mechanical energy by discharging electrodes, which can break rock. On the basis of PAPST, PPST can precisely control the discharge time and break the rock in the specified direction at the bottom of the well, so as to realize guided drilling. First, the discharge mechanism and guiding mechanism of the PPST were studied separately. Then, the discharge control model of PPST was established to explain the feasibility of using this technology to achieve drilling guidance. Finally, to verify the actual effect of this technology on rock breaking, an experiment was carried out with self-developed experimental equipment.
Through the study of the mechanism and discharge control model of PPST, it is considered that it is feasible to use this technology to achieve guidance in theory. The experimental results show that the sandstone samples were damaged and a large area of pits appeared after the shockwave, and the ultrasonic penetration test results showed that there was damage inside the rock. As the number of impacts increased, the rock damage became more severe and fracture occurred. Therefore, it is feasible to apply PPST to the directional fracture of bottom hole rock. In summary, this technology has very good application prospects.
For the first time, this paper proposed the idea of applying PAPST to steering drilling. Through the research on the steering mechanism and the experiment, the feasibility of this technology was proved and the theoretical basis was provided for the application of this technology in the field of oil drilling.
Case Study- Real Time Downhole Telemetry CCL and Tension Compression, a Differentiator for Successful Manipulation of ICD's in Horizontal Wells
Authors: Ahmed Usman , Zhang Zhiheng , Ortega Alfonzo Ruben 
Published: December 2021

Abstract
Horizontal well completions are often equipped with Inflow Control Devices (ICDs) to optimize flow rates across the completion for the whole length of the interval and to increase the oil recovery. The ICD technology has become useful method of optimizing production from horizontal wells in a wide range of applications. It has proved to be beneficial in horizontal water injectors and steam assisted gravity drainage wells.
Traditionally the challenges related to early gas or water breakthrough were dealt with complex and costly workover/intervention operations. ICD manipulation used to be done with down-hole tractor conveyed using an electric line (e-line) cable or by utilization of a conventional coiled tubing (CT) string. Wellbore profile, high doglegs, tubular ID, drag and buoyancy forces added limitations to the e-line interventions even with the use of tractor. Utilization of conventional CT string supplement the uncertainties during shifting operations by not having the assurance of accurate depth and forces applied downhole.
A field in Saudi Arabia is completed with open-hole packer with ICD completion system. The excessive production from the wells resulted in increase of water cut, hence ICD's shifting was required. As operations become more complex due to fact that there was no mean to assure that ICD is shifted as needed, it was imperative to find ways to maximize both assurance and quality performance. In this particular case, several ICD manipulating jobs were conducted in the horizontal wells. A 2-7/8-in intelligent coiled tubing (ICT) system was used to optimize the well intervention performance by providing downhole real-time feedback. The indication for the correct ICD shifting was confirmed by Casing Collar Locator (CCL) and Tension & Compression signatures.
This paper will present the ICT system consists of a customized bottom-hole assembly (BHA) that transmits Tension, compression, differential pressure, temperature and casing collar locator data instantaneously to the surface via a nonintrusive tube wire installed inside the coiled tubing. The main advantages of the ICT system in this operation were: monitoring the downhole force on the shifting tool while performing ICD manipulation, differential pressure, and accurately determining depth from the casing collar locator. Based on the known estimated optimum working ranges for ICD shifting and having access to real-time downhole data, the operator could decide that required force was transmitted to BHA. This bring about saving job time while finding sleeves, efficient open and close of ICD via applying required Weight on Bit (WOB) and even providing a mean to identify ICD that had debris accumulation. The experience acquired using this method in the successful operation in Saudi Arabia yielded recommendations for future similar operations.