bluuebunny/crossref_metadata_2025_split huggingface dataset:
Mathematical Model for Rate Transient Analysis with Additional Interface Skin for Fractured Horizontal Well With Weak Fluid Supply
Authors: Zhang Jiali , Liao Xinwei , Cao Nai 
Published: September 2021

Abstract
This paper develops a mathematical model for rate transient analysis in multi-stage fractured horizontal wells with considering weak fluid supply. A new concept of additional skin factor is introduced in the proposed model to characterize the fluid supply. Then, the mathematical model are solved by using the perturbation transformation, point source integration method, Laplace transform, and numerical inversion, while the fracture flow equations are solved by fracture discretization and superposition principle. First, the flow regimes of multi-stage fractured horizontal wells with considering weak fluid supply are identified based on the rate transient behaviors, including wellbore storage and skin effect, bilinear flow, linear flow, pseudo-radial flow in the fractured zone, interface skin effect, pseudo-radial flow in the original zone, and boundary-dominated flow. The effect of additional interface skin makes the double logarithmic curve of production rate appear an abrupt "overlap". The results of the sensitivity study show that the abrupt "overlap" becomes more obvious with the increase of the fracture conductivity, fracture number, the stress sensitivity coefficient, especially the interface skin. Finally, the proposed mathematical model is used to perform a case study on the production data of actual tight-gas wells from the Ordos Basin. The interface skin factor, fracture half-length, fracture conductivity, and boundary radius are evaluated. Through the proposed model, the characteristics of weak fluid supply in tight gas reservoirs are fully understood.
Offshore Water Treatment KPIs Using Machine Learning Techniques
Authors: Flores Lauren , Morles Martin , Chen Cheng 
Published: September 2021

Abstract
New water treatment facilities in the Gulf of Mexico include a seawater Sulfate Removal Unit (SRU) to mitigate reservoir souring and scaling. The general industry sulfate target for offshore SRU is usually 20 mg/L or even 40 mg/L; however, some facilities may require &lt;10 mg/L of sulfate in injection water, which makes water quality monitoring more critical and challenging. Current industrial practice relies on only pressure drop and a constant cleaning interval frequency to perform SRU maintenance which may result in reduced membrane life due to frequency cleaning or severe membrane fouling without the capability to predict fouling based on process conditions. The machine learning techniques applied will fill the gap and deliver a prediction model based on both simulation and real-time field data. This model will track and monitor the system key performance indicators (KPIs) including pressure, membrane fouling factor (FF), permeate sulfate concentration etc. The monitoring and prediction of these KPIs provide estimates on when the next maintenance procedure is required, track membrane system status for troubleshooting and actions, and optimize membrane performance by tuning operation conditions.
The Fall and Rise of Oilfield Ethics
Authors: Dahroug Ahmed , O’Connell Kevin 
Published: September 2021

Abstract
The oilfield is in many ways the backbone of the world economy. Historically economic recessions and booms were linked directly or indirectly to the oil price, itself governed by supply and demand. Since the start of this industry, it has experienced multiple scandals and major accidents that have affected its path to date.
In 2001 the Enron scandal of poor accounting practices shook the entire stock market, and it contributed to the complete recession in the same year. Not too long after, a supermajor revealed in 2004 a reserves accounting error that surprised the world. In 2010 the Deepwater Horizon blow out known as the "Macondo Incident" caused serious damage to the environment and significant fines to be paid in compensation due to poor engineering practice.
Incidents like these arise concurrent with times of high demand and are instructive as we study their causes and effects on the oil industry and therefore the global economy.
Areas of study for this paper include reserves/production estimation as well as ethical considerations for the oil industry at large.
Our study is based on the review of uncertainty in both the subsurface and surface parts of oil and gas production. We refer to the previous classifications of uncertainty for the subsurface part and focus on the uncertainty currently existing within the surface production system. Current surface production monitoring methods are discussed. We propose a more automated process to reduce the current uncertainty about hydrocarbon production. Artificial intelligence applicability in the surface production system is investigated.
Additionally, in this paper we review the previously mentioned poor practices and accidents briefly and use them to guide our suggestions about preventive actions to avoid future wrongdoing and incidents. We attempt to provide an objective for oilfield ethics and advocate for a unified oilfield industry code of ethics. However due to the large diversity that exists in the wide range of oilfield disciplines, a single code of ethics may not be applicable. Accordingly, we propose a guideline that may be used by different parts of the oilfield industry to develop an application-specific code of ethics. It is hoped that this guideline will guard against the gaps that may foster errors that affect the oilfield industry and global markets.
Stranger Things 3: Not All Temperature Simulators are Created Equal
Authors: Shine Joe , Heinold Thomas , Lawrence Don 
Published: September 2021

Abstract
The risk of improper temperature selection for the design and testing of cement slurries can be detrimental to well construction operations and could affect a well's integrity. The methods for temperature selection in API 10B-2 do not consistently reflect the representative bottomhole conditions for high temperature applications. More so, consider 10B-2 guidance valuable for proving benchmarks in the high temperature domain. Therefore, numerical temperature simulators help manage the risk by predicting the anticipated bottomhole cementing temperatures. Currently several temperature simulators are in use to predict, with better accuracy, cementing bottomhole temperatures. The manuscript investigates the strange differences in predictions between the simulators for a range of high temperature applications. The results of the work efforts should help end users understand the outputs allowing better judgement when selecting representative bottomhole cementing temperatures for a given application.
Improving Flow Assurance for a Waxy West African Crude Oil via Collaborative Development and Implementation of a Novel Pour Point Depressant Solution
Authors: Meister Claudia , Xu Liang , Muhammad Moin 
Published: September 2021

Abstract
An improved flow assurance solution based on a new additive with robust performance, low treat rate and versatile handling properties was developed successfully. It was applied in a waxy crude oil from West Africa with high pour point and a wax content of about 24%. Crucial for the project success was a close collaboration among all involved stakeholders from operator, service company and chemical supplier.
In the initial lab screening by the chemical supplier, tests focused on pour point, viscosity and yield stress. This approach allowed to identify the most efficient type of additive chemistry for the specific crude oil and to meet target performance requirements.
Crude oil viscosity and yield stress under pipeline operation conditions could be reduced by more than 95% while reducing the required amount of additive by more than 75% compared to the incumbent solution. This resulted in significant cost savings for the operator and in a reduction of the Health, Safety and Environmental (HSE) exposure.
Mechanical and Geometrical Tortuosities: Vanishing and Appearing Tortuosities
Authors: Samuel Robello , Lightfoot Jonathan Dale , Turner William 
Published: September 2021

ABSTRACT
Tortuosity is one of the critical factors to be considered for complex directional well trajectories, complicated build rates, precise steering in thin reservoirs, and extended reach wells. This paper discusses the pitfalls of estimating tortuosity to quantify borehole quality and answers questions, such as whether the claimed benefits (i.e., enhanced drilling performance, improved hole cleaning, ease of running casing, and superior cement operations) can be fully attributed to reduced borehole tortuosity. Running casing may mask the tortuosity present in the as drilled open hole wellbore section. This vanishing tortuosity alters the apparent "wellbore quality" and the new tortuosity representative of the cased hole path may present new appearing tortuosity. Both vanishing and appearing tortuosity are generally neglected in engineering calculations.
Conventional methods to calculate tortuosity are based on the predetermined shape of the trajectory using the minimum curvature method. Wellbore undulation (geometrical tortuosity) is determined using geometrical measurements such as inclination, azimuth, and calculated displacement; however, much of this wellbore undulation vanishes after the casing is run, and thus the cased off wellpath appears smoother. This apparent change in wellbore tortuosity results from the flexural stiffness and rigidity of the casing pipes, and the compression and tension loads along the length of the casing string. Acquiring a subsequent survey along the cased well path yields new inclinations, azimuths, and displacements. This new survey records wellpath undulations resulting from the casings path through the original open hole wellbore geometry and what we call tubular undulation (mechanical tortuosity) which is specific to the path and position of the casing within the wellbore. The smoothing of the wellpath resulting from the casing masking original wellbore tortuosity results in the original geometrical tortuosity vanishing while the new undulations resulting from the mechanical tortuosity of the casing causes additional tortuosity to appear. The comparison between the geometrical and mechanical tortuosity provides a method of quantifying the vanishing and appearing tortuosity.
Performance Evaluation of a Density Measurement Tool for ESP Applications
Authors: Ejim Chidirim , Xiao Jinjiang 
Published: September 2021

Abstract
Knowledge of fluid densities in oilfield activities is vital during production operations. The information can be used to ascertain changes in the type of produced fluids, determine water cut, gauge equipment performance, etc. This study presents the evaluation of a measurement tool that can be installed with an electric submersible pump (ESP) to measure in-situ fluid densities during production operations. Such tools can also be configured for use in non-ESP applications.
The density measurement tool has a 5.62-inch outer diameter, typical of some ESP components, which may be installed in a 7-in, 26 lb/ft casing. The tool consists of two flow sections with a 5-degree deviation angle. Total flow rates from the analysis were varied from 2000 barrels per day (bpd) to 12,000 bpd with water as the operating fluid. Pressure drop data within each flow section of the tool were obtained and the fluid densities determined. The estimated densities were compared with the known densities for water.
The results indicate that the pressure drop measurements depend on the entry distance of fluid to the first measurement point within the tool. Other contributing factors include the distance between the measurement sensors and the deviation angle between the flow sections. These factors were optimized by incorporating flow symmetry into and out of the tool to ensure reduced variability of the pressure measurements and thus enable computation of the fluid densities. Overall, incorporating the two flow sections with known deviation angle was beneficial to reduce the complexity of estimating the fluid densities. Therefore, having a simple internal flow architecture in addition to optimized pressure measurement capabilities for each flow section has the potential to estimate fluid densities. Such a tool may be used as a means to measure in-situ and surface fluid densities from flows typical of oilfield production operations. The main benefit is to obtain instantaneous fluid density mesurements for more accurate production monitoring and faster decision-making during production with an ESP.
This study presents a tool with a different internal architecture and a method that can be used to estimate fluid densities from flows typical of oilfield production operations. The tool architecture and measurement technique are simple and have the benefit of easy integration into a flow monitoring system. Such systems are of value to oilfield operators and stakeholders to optimize hydrocarbon flow and implement effective production management of field assets.
Data Driven Gas Well Performance Model Hands Back Control to Engineers
Authors: Veeken Cornelis 
Published: September 2021

Abstract
This paper presents a fit-for-purpose gas well performance model that utilizes a minimum set of inflow and outflow performance parameters, and demonstrates the use of this model to describe real-time well performance, to compare well performance over time and between wells, and to generate production forecasts in support of well interventions. The inflow and outflow parameters are directly related to well-known reservoir and well properties, and can be calibrated against common well surveillance and production data. By adopting this approach, engineers develop a better appreciation of the magnitude and uncertainty of gas well and reservoir performance parameters.
Data-Driven Optimization of Intermittent Gas Production in Mature Fields Assisted by Deep Learning and a Population-Based Global Optimizer
Authors: Gómez Javier Fatou , Omrani Pejman Shoeibi , Belfroid Stefan Philip Christian 
Published: September 2021

Abstract
In gas wells, decreased/unstable production can occur due to difficult-to-predict dynamic effects resulted from late-life phenomena, such as liquid loading and flooding. To minimize the negative impact of these effects, maximize production and extend the wells’ lifetime, wells are often operated in an intermittent production regime. The goal of this work is to find the optimum production and shut-in cycles to maximize intermittent gas production as a decision support to operators.
A framework suitable for single and multiple wells was developed by coupling a Deep Learning forward model trained on historical data with a population-based global optimizer, Particle Swarm Optimization (PSO). The forward model predicts the production rates and wellhead pressure during production and shut-in conditions, respectively. The PSO algorithm optimizes the operational criteria given operational and environmental objectives, such as maximizing production, minimizing start-up/shut-in actions, penalizing emissions under several constraints such as planned maintenances and meeting a contract production value.
The accuracy of the Deep Learning models was tested on synthetic and field data. On synthetic data, mature wells were tested under different reservoir conditions such as initial water saturation, permeability and flow regimes. The relative errors in the predicted total cumulative production ranged between 0.5 and 4.6% for synthetic data and 0.9% for field data. The mean errors for pressure prediction were of 2-3 bar. The optimization framework was benchmarked for production optimization and contract value matching for a single-well (on field data) and a cluster of wells (synthetic data). Single-well production optimization of a North Sea well achieved a 3% production increase, including planned maintenances. Production optimization for six wells resulted in a 21% production increase for a horizon of 30 days, while contract value matching yielded 29/30 values within 3% of the target. The most optimum, repeatable and computationally efficient results were obtained using critical pressure/gas flowrates as operational criteria. This could enable real-time gas production optimization and operational decision-making in a wide range of well conditions and operational requirements.
A Well-Testing Approach for Diagnostics of Fracture Complexity with Well Interference
Authors: Chen Zhiming , Liao Xinwei , Zhao Pengfei , Zhou Biao , Chen Duo , Sepehrnoori Kamy 
Published: September 2021

Abstract
Owing to well interference, the fracture geometries of child wells are sometimes more complex than initially expected. Some approaches or methodologies have been developed to evaluate the complex fracture geometries, however, the fracture geometries are still poorly understood. This work uses the boundary element method to propose a new well testing approach to determine the complex fracture geometries of child wells with inter-well interference.
It is found that the well interferences from Parent well on Child well mainly happen on the late stage, which can be physically expected. The flow regimes of Child well can be divided into: wellbore storage & skin effects, fracture bilinear flow, "fluid supply", formation linear flow, pseudo-boundary dominated flow, "well interferences", pseudo-radial flow, and boundary-dominated flow. The stage of "well interferences" occurs later with the increase in well spacing. The boundary-dominated flow is affected by the reservoir size and shape. When the reservoir size is fixed, the pressure curves in final stage of different-shape reservoirs overlap, which provides a tool to diagnose the reservoir size. While the reservoir size are variable, the occurrences of boundary-dominated flow are quite different. The smaller the reservoir, the quicker the boundary-dominated flow, which is in line with actual situations. It is also found that Parent-well rate mainly affects the flow regimes after pseudo-boundary dominated flow. That to say, after that flow regime, the performance of Child well is interfered by Parent well. The impact is more obvious with the increase in Parent-well rate, especially in pseudo-radial flow. In that flow stage, the horizontal value of pressure derivative also satisfies 0.5(qchd,D+qpar,D). In addition, when the Parent-well rate is negative, namely an injection well, the pressure derivatives of Child well decrease sharply, which means that the pressure depletion of Child well decreases and it is helpful to production of Child well. When the Parent-well rate is a positive and large value, the pressure depletion of Child well increase sharply and its production is harmed by the Parent well. Thus, there should be an optimized production strategies between Parent well and Child well. Finally, the model application on diagnostics of fracture complexity of an actual well is performed. This study provides a new way to identify the fracture geometries of child wells in unconventional plays.
Quantifying the Effect of Stress Hysteresis on the Drilling Window: How Mud Weight Variations Can Affect Wellbore Strength
Authors: AlBahrani Hussain , Morita Nobuo , Alqam Mohammad 
Published: September 2021

Abstract
The estimation of the drilling window limits ensures that lost circulation and wellbore instability events are minimized. These limits are conventionally defined during the pre-drilling phase based on offset wells data. As drilling commences, mud weights are selected to fit within these limits and they can be adjusted to react to different drilling scenarios as long as they don't violate the defined limits. This process fails to consider the effect of the initial mud weight and its subsequent adjustments on the strength of the wellbore. The concept of stress hysteresis dictates that when a body is subjected to a certain load, such as the one exerted by the hydrostatic pressure of the mud, its state will be altered in a manner that can shift its strength limits. This work presents a model that quantifies the changes in the drilling window due to variations in mud weight. The objective is to ensure that any subsequent mud weight changes will fall within the updated drilling window limits.
The analysis is carried out using a novel process of a 3D poro-elasto-plastic finite element model (FEM) that is integrated with a machine learning (ML) algorithm. The integrated FEM-ML model uses offset wells data along with the best fitting failure criterion to estimate the initial limits of the drilling window. The offset wells data used consist of wireline logs, drilling reports, and mechanical testing lab results belonging to the formation of interest. The integrated model uses this data to estimate the stress distribution and learn the failure patterns. The model is then used to run different scenarios of mud weight variations while drilling a specific hole section to quantify their effect on the drilling window. The end result of each scenario is an update of the drilling window, which reflects the effect of stress hysteresis.
When examining the initial estimations of the drilling window against those reflecting the stress path effect, a significant discrepancy in the window size is quantified. This examination is carried out for an offset well, which experienced multiple mud weight changes as a response to various drilling events. Subsequently, the changes in the drilling window and the actual mud weights used are analyzed in view of the drilling difficulties experienced in that specific offset well for the purpose of providing a form of validation. The model results show that the drilling window had shrunk significantly enough for the mud weight to violate the wellbore stability limit. Failure to consider the stress hysteresis effect in this well led major wellbore instability, tight hole, and overpull.
The modelling effort presented in this work allows for a new aspect of dynamic responses to drilling events as they occur.
Wettability Characterization from Pore-Scale Images Using Topology and Energy Balance with Implications for Recovery and Storage
Authors: Blunt Martin , Kearney Luke , Alhosani Abdulla , Lin Qingyang , Bijeljic Branko 
Published: September 2021

Abstract
We present two methods to measure contact angles inside porous media using high-resolution images. The direct determination of contact angle at the three-phase contact line is often ambiguous due to uncertainties with image segmentation. Instead, we propose two alternative approaches that provide an averaged assessment of wettability. The first uses fundamental principles in topology to relate the contact angle to the integral of the Gaussian curvature over the fluid-fluid meniscus. The advantage of this approach is that it replaces the uncertain determination of an angle at a point with a more accurate determination of an integral over a surface. However, in mixed-wet porous media, many interfaces are pinned with a hinging contact angle. For predictive pore-scale models, we need to determine the contact angle at which displacement occurs when the interfaces move. To address this problem we apply an energy balance, ignoring viscous dissipation, to estimate the contact angle from the meniscus curvature and changes in interfacial areas and saturation. We apply these methods to characterize wettability on pore-scale images of two- and three-phase flow. We also discuss the implications of the results for recovery and storage applications.