bluuebunny/crossref_metadata_2025_split huggingface dataset:
Application of 3D Geomechanical Research for De-Risk and Improve High Pressure and High Temperature Well Drilling
Authors: Yi Ming , Liu Ling , Wei Qiang , Chen Liang , Li Binging , Guo Zhiqi , Xu Yangyang , Huang Xingning 
Published: May 2021

Abstract
Exploration focus is moving into deeper targets of high pressure and high temperature (HPHT) regime due to the ever-increasing energy demand of China. Overpressure and wellbore instability related problems in such setting are mainly associated with narrow drilling margin resulting in severe well control incidents and increased drilling cost. In order to reduce drilling risks and operation costs, an accurate geomechanical model is necessary. The model provides technical support for drilling process and minimum reservoir damage due to optimal mud weight program. Well-scale (1D) Mechanical Earth Model (MEM) is constructed on the offset wells which consist of rock strength properties and stress profile by incorporating all available data including open hole log data, geomechanical core lab results, LOT/FIT, direct pore pressure measurements and drilling events. Furthermore, 3D geomechanics model is generated using available well-scale MEM data in the field and distributed throughout the field which guided by seismic interpretation data as distribution control. The 3D geomechanical model is used to design mud weight and casing program for the upcoming well. The offset wells in the study areas were drilled through complex geological settings with high overpressure (13500 psi) and high temperature (200-220 deg C). Therefore, drilling operations is also risky with different types of drilling events encountered frequently including stuck pipe, inflow, losses and connection gas etc. With 3D geomechanical model as the foundation, the integrated approach helps ultra-deep wells to reduce serious wellbore instability caused by abnormal formation pressure, wellbore collapse and other complex drilling problems. The implementation of systematic and holistic workflow has proven to be extremely successful in supporting the drilling of HPHT wells in China. The integrated solution has been applied in the ultra-deep well, recorded an improvement in ROP by 35.3% and decrease no-productive time (NPT) by 25.3% compared with offset well. The geomechanical approach provides a convenient means to assist field engineers in the optimization of mud weight, risk assessment, and evaluation of HPHT wells drilling performance. The findings will provide reference and guideline for de-risk and performance improvement in HPHT wells drilling.
Drilling System Optimization Leads to Expedited Wells Delivery
Authors: Ovwigho Efe Mulumba , Al Marri Saleh , Al Hajri Abdulaziz 
Published: May 2021

Abstract
On a Deep Gas Project in the Middle East, it is required to drill 3500 ft of 8-3/8" deviated section and land the well across highly interbedded and abrasive sandstone formations with compressive strength of 15 - 35 kpsi. While drilling this section, the drill string was constantly stalling and as such could not optimize drilling parameters. Due to the resulting low ROP, it was necessary to optimize the Drill string in order to enhance performance.
Performed dynamic BHA modelling which showed current drill string was not optimized for drilling long curved sections. Simulation showed high buckling levels across the 4" drill pipe and not all the weight applied on surface was transmitted to the bit. The drilling torque, flowrate and standpipe pressures were limited by the 4" drill pipe. This impacted the ROP and overall drilling performance. Proposed to replace the 4" drill pipe with 5-1/2" drill pipe. Ran the simulations and the model predicted improved drill string stability, better transmission of weights to the bit and increased ROP. One well was assigned for the implementation.
Ran the optimized BHA solution, able to apply the maximum surface weight on bit recommended by the bit manufacturer, while drilling did not observe string stalling or erratic torque. There was also low levels of shocks and vibrations and stick-slip. Doubled the on-bottom ROP while drilling this section with the same bit. Unlike wells drilled with the previous BHA, on this run, observed high BHA stability while drilling, hole was in great shape while POOH to the shoe after drilling the section, there were no tight spots recorded while tripping and this resulted in the elimination of the planned wiper trip. Decision taken to perform open hole logging operation on cable and subsequently run 7-in liner without performing a reaming trip. This BHA has been adopted on the Project and subsequent wells drilled with this single string showed similar performance. This solution has led to average savings of approximately 120 hours per well drilled subsequently on this field. This consist of 80 hours due to improved ROP, 10 hrs due to the elimination of wiper trip and a further 30 hrs from optimized logging operation on cable. In addition, wells are now delivered earlier due to this innovative solution.
This paper will show how simple changes in drill string design can lead to huge savings in this current climate where there is a constant push for reduction in well times, well costs and improved well delivery. It will explain the step-by-step process that was followed prior to implementing this innovative solution.
Mitigating Twist-Offs While Drilling with the Help of BHA Dynamics Software
Authors: Rivas Mario A. , Ramirez Andres A. , Al-Zahrani Bader S. , Abouelnaaj Khaled K. 
Published: May 2021

Abstract
One of the major challenges the Oil and Gas Industry faces nowadays during drilling operations is the twist-offs on Bottom Hole Assembly (BHA) components such as Drilling Jars, Shock Tools, Mud Motors, Roller Reamers, Stabilizers, Drill Collars, PBLs, Heavy Weight Drill Pipe (HWDP), Drill Pipe (DP), etc. To overcome this challenge, an initiative was proposed by performing a study based on twist-offs experienced on BHA components while drilling operations and recommendations are provided to reduce and eliminate twist-offs related to drilling with suboptimal drilling parameters.
The statistical data for the twist-off events was collected coming from Daily Drilling Reports, and the analysis was limited to all wells which presented twist-offs on the drillstring and BHA components. Three examples of twist-offs due to drilling with erratic torque are discussed as well as a successful example of drilling parameters optimization.
The three examples which presented drillstring and BHA twist-offs were analyzed using available BHA Dynamics and vibrations software and it was discovered that the parameters utilized (operational RPM) fell within the critical zone shearing force peaks (resonance vibrations). The components with the most twist-offs were identified. The hole size where we have the most twist-offs were also identified, which will help in focusing on these areas for the recommendations provided.
This analysis will help Drilling Engineers and Foremen to foresee vibration dysfunctions and act accordingly by the use of available BHA Dynamics software in order to optimize drilling parameters before and during drilling. By drilling within a safe operating RPM window (away from resonant RPM), there will be reduction in the number of twist-offs and associated lost time.
Packer-Setting Methodology with Auto-Fill Capability and Interventionless Valve Reduces Completion Cost
Authors: Md Noor Mohd Nazri , Abreu Javier , Demyanov Alexandr , Batita Nabil 
Published: May 2021

Abstract
A new valve has been designed and qualified to reduce interventions during packer-setting operations. In a typical well, completion with a hydraulic-production packer, the tubing string must be plugged to create the required pressure differential for packer actuation. At desired depth, delivering a preselected circulation rate actuates the tool and converts the string to a closed system, enabling the packer to be set hydraulically.
Before designing the valve, an operator's engineering and operational requirements were collected and understood. Then a conceptual design was evaluated, and a prototype device was manufactured. The valve was tested for autofill capability, actuation parameters and pressure integrity. The critical design elements of the valve are the choking and spring mechanisms, which enable circulation without prematurely actuating the valve and then enable tubing autofill. A visual inspection post qualification test was conducted to validate the components’ condition and integrity. During the qualification process, the valve working envelope was developed.
After the successful qualification test, the valve was deployed in a customer well with a production packer that has a blanking device consisting of a ceramic disc. Prior to deployment, hydraulic simulation was done to determine the required flow rate to achieve desired pressure drop across the valve for actuation. During deployment, the tubing was filled automatically, validating the valve autofill capability. Upon reaching setting depth, the completion string was circulated at the required circulation rate to actuate the valve and close the system.
Pressure integrity in the tubing validated the valve functionality. Surface pressure was applied against the blanking device, and the production packer was set hydraulically. Subsequently, before completing the well, the blanking device was broken using a slickline run, and the well was put on production.
The deployment technique using the valve requires only one slickline run whereby in typical operation four slickline runs are required.
This project represented true problem-solving engineering approaches. The operator requirements were properly understood and conceptual design was validated, and product realization phase was initiated. The efficient product development methodology improves the lead time from conceptualization to product realization. During the first well deployment, hydraulic simulation during the prejob planning proved to be critical to understanding the required circulation rates to actuate the valve.
A Novel Water-Based Drilling Fluid Tailored for Challenging Slanted HTHP Wells
Authors: Traboulay Vaughn Reza , Aung Tint Htoo , Manzoleloua Cedric , Panamarathupalayam Balakrishnan , Arena Carmelo , DMello Allwyn , Sebelin Linus , Eyaa Clotaire 
Published: May 2021

Abstract
High-temperature water-based drilling fluid systems hold several advantages over synthetic based systems from financial and environmental viewpoints. However, most conventional water-based systems start to become unstable at temperatures above 300 degF. This paper details the design and implementation of A Novel Water-Based Drilling Fluid that meet these temperature stability requirements.
The newly developed high-temperature water-based system discussed in this paper utilizes a custom-made branched synthetic polymer that exhibits superior rheological properties and fluid loss control as well as long term stability above 400 degF. The branched synthetic polymer is compatible with most oilfield brines and maintains excellent low-end rheology necessary for hole cleaning and solids suspension under high-temperatures and pressures. Under static conditions, the high-temperature fluid shows no gelation resulting in lower swab surge pressures while the stability of the highly branched synthetic polymer and enhanced rheological profile minimize sag.
To drill a challenging exploration well, a Middle East client required a cost-effective drilling fluid system which remains stable under static temperatures expected to exceed 375 degF. The long-term stability of the system was critical for successful wireline logging operations. In addition, the system was required to provide shale inhibition, hydrogen sulfide suppression and sufficient density (above 16.5 lbm/galUS) to maintain well integrity while drilling through anticipated high-pressure zones. The challenging intermediate (12.25-in and 8.375-in) and reservoir (6-in) sections were successfully drilled and evaluated using this new branched synthetic polymer-based system. Fluid property trends and system treatments will be detailed alongside thermal stability data for extended periods required for wireline logging (up to 9 days static).
This paper will discuss how proper laboratory design of the high-temperature water-based system was translated to excellent field performance and will indicate how this technology can be utilized for future campaigns in the region and worldwide.
Nitrogen-Based Back Pressure Unit Modernizes Managed Pressure Drilling Operations
Authors: Al-Hashmy Wamidh Louayd 
Published: May 2021

Abstract
Managed Pressure Drilling (MPD) solutions are no longer the anomaly to Operator strategies, but rather another tool in their belts. With this continual utilization, MPD is evolving to become compact, more effective and safer. The inventive use of a Nitrogen Backup Unit (NBU) has eliminated the reliance of MPD operations on sizable Auxiliary Pumps.
The core function of MPD operations is maintaining the total wellbore pressure by manipulating surface applied back pressure. MPD relies on circulating fluid as back pressure is generated by restricting flow against its choke(s). While drilling, fluid circulation is a given; however, that is not the case during static conditions such as drill string connections. The NBU solves this issue by injecting a small volume of nitrogen into the MPD lines upstream of the choke at a pre-set pressure. This supplements the back pressure control at surface should additional pressure be needed after closing the choke or if pressure diminishes during long static periods.
Prior to the NBU design, the only effective solution was an Auxiliary Pump setup. This solution doubles the choke manifold footprint, relies on mechanical maintenance, and requires additional dedicated personnel at times. Most critically, the Auxiliary Pump lags the operation minutes before each use and is therefore functioned before static conditions when possible. However, unplanned and sudden events are commonplace – such as Rig Pump failures. When drilling formations with narrow pressure margins, unsafe gases, or crucial hole instability pressure limits, a few minutes can result in considerable and costly outcomes. Once installed during initial rig-up, the NBU is capable of injecting nitrogen-sourced back pressure instantaneously at the literal click of a button – avoiding costly and sometimes hazardous conditions.
The NBU modernizes MPD operations and renders the Auxiliary Pump setup outdated in many applications. This paper details this innovative implementation of maintaining wellbore pressure, highlights several field examples of the NBU maintaining back pressure at critical times and shows how the layout used minimizes the operational footprint.
Design of Horizontal Wellbore in Dadas Shales of Turkey by Considering Wellbore Stability and Reservoir Geomechanics
Authors: Merey Sukru , Polat Can , Eren Tuna 
Published: May 2021

Abstract
Currently, many horizontal wells are being drilled in Dadas shales of Turkey. Dadas shales have both oil (mostly) and gas potentials. Thus, hydraulic fracturing operations are being held to mobilize hydrocarbons. Up to 1000 m length horizontal wells are drilled for this purpose. However, there is not any study analyzing wellbore stability and reservoir geomechanics in the conditions of Dadas shales. In this study, the directions of horizontal wells, wellbore stability and reservoir geomechanics of Dadas shales were designed by using well log data. In this study, the python code developed by using Kirsch equations was developed. With this python code, it is possible to estimate unconfined compressive strength in along wellbore at different deviations. By analyzing caliper log, density and porosity logs of Dadas shales, vertical stress of Dadas shales was estimated and stress polygon for these shale was prepared in this study. Then, optimum direction of horizontal well was suggested to avoid any wellbore stability problems. According to the results of this study, high stresses are seen in horizontal directions. In this study, it was found that the maximum horizontal stress in almost the direction of North-South. The results of this study revealed that direction of maximum horizontal stress and horizontal well direction fluid affect the wellbore stability significantly. Thus, in this study, better horizontal well design was made for Dadas shales. Currently, Dadas shales are popular in Turkey because of its oil and gas potential so horizontal drilling and hydraulic fracturing operations are being held. However, in literature, there is no study about horizontal wellbore designs for Dadas shales. This study will be novel and provide information about the horizontal drilling design of Dadas shales.
Application of Machine Learning Techniques for Real Time Rate of Penetration Optimization
Authors: Elmgerbi Asad Mustafa , Ettinger Clemens Peter , Tekum Peter Mbah , Thonhauser Gerhard , Nascimento Andreas 
Published: May 2021

Abstract
Over the past decade, several models have been generated to predict Rate of Penetration (ROP) in real-time. In general, these models can be classified into two categories, model-driven (analytical models) and data-driven models (based on machine learning techniques), which is considered as cutting-edge technology in terms of predictive accuracy and minimal human interfering. Nevertheless, most existing machine learning models are mainly used for prediction, not optimization. The ROP ahead of the bit for a certain formation layer can be predicted with such methods, but the limitation of the applications of these techniques is to find an optimum set of operating parameters for the optimization of ROP. In this regard, two data-driven models for ROP prediction have been developed and thereafter have been merged into an optimizer model. The purpose of the optimization process is to seek the ideal combinations of drilling parameters that would lead to an improvement in the ROP in real-time for a given formation.
This paper is mainly focused on describing the process of development to create smart data-driven models (built on MATLAB software environment) for real-time rate of penetration prediction and optimization within a sufficient time span and without disturbing the drilling process, as it is typically required by a drill-off test. The used models here can be classified into two groups: two predictive models, Artificial Neural Network (ANN) and Random Forest (RF), in addition to one optimizer, namely genetic algorithm. The process started by developing, optimizing, and validation of the predictive models, which subsequently were linked to the genetic algorithm (GA) for real-time optimization. Automated optimization algorithms were integrated into the process of developing the productive models to improve the model efficiency and to reduce the errors.
In order to validate the functionalities of the developed ROP optimization model, two different cases were studied. For the first case, historical drilling data from different wells were used, and the results confirmed that for the three known controllable surface drilling parameters, weight on bit (WOB) has the highest impact on ROP, followed by flow rate (FR) and finally rotation per minute (RPM), which has the least impact. In the second case, a laboratory scaled drilling rig "CDC miniRig" was utilized to validate the developed model, during the validation only the previous named parameters were used. Several meters were drilled through sandstone cubes at different weights on bit, rotations per minute, and flow rates to develop the productive models; then the optimizer was activated to propose the optimal set of the used parameters, which likely maximize the ROP. The proposed parameters were implemented, and the results showed that ROP improved as expected.
The Hard Case for Whole Drilling Optimization
Authors: Damski Carlos , El Afifi Sameh 
Published: May 2021

Abstract
Today every Oil & Gas company is searching for the elusive drilling optimization process. Authors argue that a global drilling optimization is only achieved calculating the actual ROI – based on money spent in drilling vs total production of the well. As this is impractical, this paper presents a framework to measure engineering and management aspects of this optimization. Engineering approach looks into "doing things right," while managerial attitude is "doing the right things."
Drilling optimization is centered in using existing (and upcoming) data from rig and its analyses. Engineers look into hydraulics, WOB, etc., with the purpose to calculate ideal/best ROP parameters and eventually to avoid problems, such as stuck pipe. This is done by direct calculation and/or running simulated models to spot deviations.
Management is concerned with relative efficiency of the process (KPIs) compared to a baseline (offset wells, planned durations, technical limits, etc.). They concentrate at comparisons and focus at how to mitigate operational risks (time, costs, HSE, etc.) while producing the "best well".
Those two intertwined optimization processes are depicted and explained in the next sessions.
Authors' experience has shown that TL (Technical Limit), ILT (Invisible Lost Time) and NPT (Non-Productive time) are façades from the engineering and management efforts in drilling optimization. For example, there is no unique way to describe "Technical Limit" in drilling. We will describe the technical components for it under physics and models, as well as under historical-coaching-KPI approach. Same for ILT and NPT.
Under a unique framework, users can understand and clarify the confusion in the current marketplace to better data and data processing to achieve optimization.
The so called "data analytics" is dissected and formalized so all parties involved: technicians, service providers, operators, equipment suppliers, managers, finances, etc., can fully understand where data can be used (also how they are collected and quality checked) and what processes are needed to achieve each step of the drilling optimization.
Unlike any product or service available today, the framework described in this article looks in the drilling optimization with a holistic view. Efforts so far have been scattered and there is a lack of an overall framework. The best results come from the combination of those two approaches.