bluuebunny/crossref_metadata_2025_split huggingface dataset:
Material Selection, Compound Development Criteria and Elastomer Grade Optimization of Packer Element in CCUS Storage Well
Authors: Meng S. , Ren J. X. , Cheng P. , Li J. Y. , Qi C.Y. 
Published: September 2024

Abstract
CO2 storage is an integral part of CCUS, whereas packer element for CO2 storage well is an essential component that must perform reliably for decades. The key to superior reliability is a high performing elastomer. This paper intends to compare the elastomers in oilfield applications and recommend the best fit for packer element under field application. It identifies the major packer element failure mode, establishes the compound development criteria, and ultimately guides elastomer grade optimization.
The sealing performance of packer element in CO2 well was reviewed, and the major failure modes identified. The compound development criteria were established successively. The characteristics of the elastomers in oilfield were evaluated for packer element application in CO2 storage well. The best elastomer was selected based on the criteria established. Special attention was paid to the optimal selection of elastomer grades. The effect of macromolecular structures on the compatibility of CO2 was studied from the thermodynamics aspect and later investigated by the immersion testing of different elastomer in supercritical CO2 and brine mixture under downhole temperature and pressure.
The major cause of long-term failure of packer element has been found to be the compatibility between CO2 and elastomer. The major cause of short-term failure is the rapid gas decompression (RGD) damage. Hence, the compound development criteria are set to be CO2 compatibility, RGD resistance, low temperature flexibility and chemical resistance. Upon the characteristics comparison of ethylene propylene diene monomer rubber (EPDM), Nitrile Butadiene Rubber (NBR), Hydrogenated Nitrile Butadiene Rubber (HNBR), and Fluroelastomer (FKM), HNBR is the best candidate meeting all criteria under field condition. To maximize the material life of HNBR packer element, one needs to design the formulation with a HNBR grade that is thermodynamically incompatible with supercritical CO2. However, selecting an optimal HNBR grade is a debatable subject in the industry. Some prefer low ACN grades while many others prefer high ACN ones. The dispute on HNBR grade selection may be reconciled by our immersion testing results indicating that as the ACN content of HNBR goes up, the material suffers more mass loss as well as volume increases and tends to have more bubbles and blisters on surface. On the other side, the higher ACN grades retain the mechanical properties better than the lower ACN ones.
High performing elastomer for packer element can significantly improve the reliability and reduce the operation cost of CO2 storage wells and overall CCUS value chain. Selecting the best elastomer is essential to the packer element performance. This paper is one of the first attempts to address the issues of elastomer selection, compound development criteria, and elastomer grade optimization. Our results may resolve a long-standing dispute in the industry.
Digital Twin for Optimization of Wells with Intelligent Completion
Authors: Srivastava S. , Gambaretto A. , Shresth K. 
Published: September 2024

Abstract
The evaluation and optimization of wells with intelligent completion, whether multilayer or multilateral, requires a deep understanding of inflow characteristics at each inflow control valve (ICV). Zonal testing is crucial for gathering fluids and reservoir data; nonetheless, it leads to production deferment, which is undesirable by most operators.
In this paper, we present how a wells’ digital twins on an edge Internet of Things (IoT) device will provide real-time virtual measurements as well as ICV optimization opportunities to maximize oil production. We present a digital twin solution for a synthetic well equipped with an electric submersible pump (ESP) and two ICVs. The digital twin system is composed of two primary components together called the estimator. One aspect is a physics-based well model that accurately calculates pressure losses and flow characteristics, and the other is an iterative algorithm that employs real-time field data, encompassing production and ESP operational data to dynamically recalibrate and update the digital twin representation of the well. By capturing the well’s dynamic state, the digital twin enables the optimizer, an optimization workflow that suggests optimal ICV positions and ESP pump frequencies, aiming to maximize oil production while maintaining water-cut constraints within individual layers. To validate the approach, we rigorously tested various well scenarios. Our approach involved flow tests with different ICV positions. In addition, we conducted a comprehensive parametric analysis, considering temporal variations in water cuts and the productivity index (PI) of individual layers. Recognizing that factors such as pressure fluctuations, wellbore conditions, and reservoir dynamics significantly impact overall productivity and inflow characteristics, the estimator within the digital twin avatar of the well is automated to allow fine tuning of PI and/or water cut for each layer to recalibrate itself dynamically. The estimator adeptly captures transient changes in the well, and our results demonstrate that initial calibration efforts substantially enhance its accuracy over time. The optimizer, an extension of the digital twin model, is tested against operational constraints of oil and water production to recommend ICV positions with projected flow rates and water cuts for each layer. Our findings align closely with a physics-based simulator, validating the approach within a 10% error range.
This entire digital twin workflow helps provide a consistent and reliable well monitoring mechanism for the well along with reliable recommendations for production optimization decisions. The novelty in this approach is to provide accurate real-time flowrate estimates of complex multilateral/multilayer wells with intelligent completions. The digital twin workflow provides virtual sensing that helps estimate downhole well conditions with great reliability for production management and optimization.
A Novel Solid Lubricant Designed Using Tribology Science Reduces the Torque and Improve ROP in Water Base Mud Wells in the Llanos Basin and Magdalena Valley of Colombia
Authors: Ramirez Mario A , Jensen Terrel , Trebilcock Mauricio , Castellanos Jaime 
Published: September 2024

Abstract
An Operator in Colombia was experiencing torque issues in a water-based fluid system while drilling wells in the Middle Magdalena and Llanos basins. To address these torque issues, a novel solid lubricant was presented to the operator by the fluid service provider and product manufacturer. Through an extensive lab testing profile, utilizing traditional testing protocols in addition to introducing tribology, the lubricant was selected for field trials. Further testing of the field samples was completed, and data collected from the wellsite demonstrated torque reduction and increased rate of penetration (ROP) allowing the operator to complete the interval.
Tribology uses a different approach to explain stick-slip phenomena and variations of torque and drag. Tribometer results are plotted on a Stribeck curve to display the coefficient of friction as a non-linear function of the contact load. This shows the continuous variations in the different lubrication regimes. The coefficient of friction (COF), static, is due to the contact between bottom hole assembly (BHA) and wellbore is recurrent while drilling directional wellbores.
Tribometer results demonstrated the solid lubricant adhered to the disk asperities, reducing the difference between static and dynamic coefficients of friction. This reduction was confirmed during the field trial and additionally the ROP was increased after the addition of the lubricant. Use of a single value COF to build torque and drag modeling produces an oversimplified representation of a lubricant’s COF improvement. When instead using a tribometer to create a Stribeck curve a lab’s results produce applicable data, as it incorporates variations of rotation and load. More attention should be dedicated to the performance of lubricants in the boundary condition in directional wells as this represents the torque required to initiate rotation and overcome differential pressure while making connections. Use of the novel lubricant reduces static COF and breakover torque.
Tribology, the science of friction, lubrication and wear has been used in automotive, space, pharmaceutical and mechanical engineering industries among others for years for the design and evaluation of solid and liquid lubricants. Unfortunately, this is not a common practice in the oil and gas industry. Tribology allows better understanding of wellbore lubrication throughout the different regimes and under differing loads. Tribology is a new method to measure the complex phenomena of lubricity in the oilfield. It helps better understand items such as stick-slip and torque variations while drilling and how they can be explained through analyzing their behavior along the Stribeck curve.
Enhancing CO2 Injector Well Performance with GRE Lined Tubing: A Technical Evaluation
Authors: Ismail M. Izuddin , Wahi M. Wahidullah Moh , Lokman M. Elham , Amir M. Syafeeq Ebining , Omar M. Haizal , Fernandes A. 
Published: September 2024

Abstract
Carbon capture and storage (CCS) technology has emerged as a pivotal strategy in mitigating greenhouse gas emissions and combatting climate change. An integral component of CCS systems is the injection of captured carbon dioxide (CO2) into geologic formations, often via dedicated injector wells. The efficiency and safety of these injector wells are of paramount importance. This technical paper presents a comprehensive study on the application of Glass-Reinforced Epoxy (GRE) lined tubing to enhance the performance and longevity of CO2 injector wells.
The use of GRE lined tubing has gained traction in various industrial applications due to its exceptional corrosion resistance, mechanical strength, and long-term durability. This paper outlines the material properties and manufacturing processes associated with GRE lined tubing, emphasizing its suitability for the harsh conditions encountered in CO2 injection wells.
Key aspects of the study include:
Material Selection: A detailed analysis of GRE lined tubing's chemical resistance and mechanical properties in the context of CO2 injection environments, highlighting its advantages over traditional materials. Corrosion Resistance: A comprehensive investigation into GRE lined tubing's resistance to CO2-induced corrosion, offering insights into the potential for reduced maintenance and increased operational lifespans. Hydraulic Performance: Assessment of the tubing's hydraulic properties, including flow rate and pressure drop characteristics, to ensure efficient CO2 injection. Long-Term Reliability: A discussion of GRE lined tubing's resilience to cyclic loading, temperature fluctuations, and exposure to high-pressure CO2, demonstrating its suitability for extended service life. Safety Considerations: An examination of safety implications and regulatory compliance associated with using GRE lined tubing in CO2 injector wells, focusing on leakage prevention and environmental protection. Case Studies: Real-world examples and case studies showcasing successful implementations of GRE lined tubing in CO2 injector wells, highlighting improved operational efficiency and reduced downtime.
The findings from this study offer valuable insights into the benefits of employing GRE lined tubing in CO2 injector wells. By enhancing corrosion resistance, improving hydraulic performance, and ensuring long-term reliability, this innovative material can contribute to the efficiency and sustainability of CCS systems, ultimately advancing efforts to reduce carbon emissions and combat climate change.
Comprehensive Experimental and Simulation Studies on Capillary Pressure in Unconventional Production and CO2 Sequestration
Authors: Neshat S. S. , Greene J. T. , Newsham K. E. , Xie X. , Keating J. F. 
Published: September 2024

AbstractCapillary pressure measurements on shale and tight core samples have revealed that this parameter can reach hundreds or even thousands of psi at reservoir conditions. A high pressure difference between the fluid phases can significantly affect the multiphase flow in the reservoir, but this parameter is usually neglected in analytical and numerical unconventional reservoir modeling. This study presents a systematic and comprehensive evaluation on the coupled effects of capillary pressure and wettability on unconventional production and CO2 sequestration. Mercury injection capillary pressure (MICP) measurements were performed on hundreds of Permian Basin core samples based on facies-driven selection criteria. Both mercury intrusion (pressurization) and extrusion (depressurization) were recorded for all samples to represent drainage and imbibition processes, respectively. The exhaustive experimental dataset was used to create type drainage-imbibition curves for capillary pressure and relative permeability in six dominant facies in the Permian Basin. Systematic field-scale mechanistic simulations were performed to evaluate the effect of all integrated parameters on oil production and sequestration. Simulation results show that capillary pressure decreases water cut in water-wet formations and increases it in oil-wet reservoirs. In a long-term CO2 sequestration scenario, high displacement pressure in the matrix constrains gas propagation and storage capacity in shale rocks.
Distributed Acoustic Sensing of Passive and Active Inflow Control Technology and Quantification of Flow Rates for Reservoir Surveillance
Authors: Schaeffer B. , Grubert M. , Jugdaw S. , Allen C. , Corona Cortes G. , Jaaskelainen M. , Satti R. , Ellmauthaler A. , Maida J. , McPhail P. , Wilson G. 
Published: September 2024

Abstract
The application of distributed acoustic sensing (DAS) technology has continued to gain popularity and develop rapidly as a diagnostic tool within intelligent completions outfitted mature fields oil and gas wells, for the purpose of production and injection flow monitoring. Intelligent completion wells consist of subsurface valves placed at tailored depth increments which allows for the passage and restriction of flow in both a passive and active sense. The fluidic autonomous inflow control devices (AICDs) operate passively without moving parts or electronics and are designed to preferentially restrict unwanted fluids at breakthrough from the formation. Interval control valves (ICVs), in contrast, are controlled from the surface to adjust and expose flow ports which regulate flow. The following research involves a set of experiments about which a multiphase flow loop (oil, water, gas) was instrumented with a DAS system across an inflow test section that included both AICDs and ICVs. The experiments sampled realistic subsurface flow rates for both injection and production scenarios and sample fluid properties, where the composition was varied in two phase (100% oil to 100% water) and three phase mixtures (oil/water mix to 100% gas). The DAS data was acquired continuously with a temporal sampling frequency of 40 kHz which enabled an analysis of both the transient and steady state flow behavior. Electronic reference hydrophone and accelerometer data were also acquired to provide insights in supporting the DAS interpretation. Results from the single phase (100% water) injection flow configuration display a direct relationship between the acoustic response of the DAS acquired data at the ICV position along the flow loop with respect to choke settings and flow rates. Multiphase production flow quantification for both ICV and AICD configurations are significantly more complex than single phase injection flow given the range of fluid mixtures that may be present in field acquired data, however initial results from flow loop data are encouraging and require continued investigation. The complete dataset acquired at the flow loop provides a novel resource for the development of machine learning models which utilize DAS acoustic features, as well as other available data such as pressure gauge measurements, to estimate both flow rates and fluid composition. The pairing of these technologies will enable a realtime quantification of inflow rates per zone and provide operators with the necessary data to optimize reservoir management.
Time Dependent Conductivity of In-Basin Regional Sands
Authors: Duenckel R. J. , Barree R. D. , Sutter Kimberly , Hlidek B. T 
Published: September 2024

Abstract
Baseline conductivity of a proppant pack is to be measured and reported at 50 hours at constant stress according to procedures set out in API RP 19D. However, it has long been recognized that conductivity at stress continues to decline beyond 50 hours - 50 hours being a rather arbitrary timeframe. Thus, conductivity at a given stress is time dependent. This Time Dependent Conductivity (TDC) should be determined and included in predictions of fractured well performance.
Studies of the decline of proppant conductivity with time at stress have been published by numerous authors over the last few decades. These studies however were confined to traditional proppants: i.e., ceramic proppants of variable densities, northern white sands and Brady (brown) sands. These studies preceded the advent of the utilization of regional sands now dominating the selection of proppants for fracturing in North America.
A methodology for predicting conductivity as a function of time and stress for the traditional proppants had previously been proposed by the Stim-Lab Proppant Consortium. A series of conductivity tests have been conducted on numerous regional sands to obtain the required data and extend this methodology to these materials - and thus compare to the traditional northern white and Brady (brown) sands. The result of this study shows that while the 50-hour conductivities at stress (per API RP 19D) of regional sands are often reasonably acceptable, in general the rate of conductivity decline over time for the tested regional sands is nearly always greater, and in some cases significantly greater, than that of northern white and Brady sands.
Further, it was observed that the rate of conductivity decline is a function of the material properties such as shape and crush resistance and not related to sieve distribution or concentration. Also, since the minerologies of the tested regional sands are similar to the northern white and Brady sands with silica dominating, the difference in conductivity performance is concluded to be the result of the differing crystalline structures, shapes and/or impurities of the silica grains.
Recognition and definition of the degree to which conductivity decreases as a function of time may aid in proppant selection and in propped fracture performance predictions.
Development and Application of HUST: A Hydrogen Underground Storage Screening and Ranking Tool Incorporating Operational Considerations, Geochemical and Microbial Reactions
Authors: Sekar L. K. , Okoroafor E. R. 
Published: September 2024

Abstract
Several attempts have been made to develop site selection criteria for underground hydrogen storage (UHS) in porous media (UHS-PM). Existing site selection criteria do not consider geochemical reactions and microbial interactions, which are critical processes in UHS-PM. The objective of this work is to share the development of a comprehensive UHS-PM site selection tool and its application in the Sacramento Basin. This work involved building an innovative open-source tool to optimize UHS site selection operations of the saline aquifers for subsurface hydrogen storage. This tool works on the principle of multi-stage screening based on UHS's hydrodynamics, operational, geochemical, and microbial perspectives. The multi-stage screening takes place in three stages. Stage 1 considers the productivity index as the main output and identifies the most important variables affecting hydrogen recovery. Stage 2 is built upon the screening criterion developed from the literature by identifying the conditions that lead to the losses of the injected hydrogen through geochemical reactions. Stage 3 is based on processes that could lead to losses based on the possible presence of microbes. The workflow also has the option to consider the weightage of each physical process, which leads to a more rigorous approach to UHS site selection. The site selection was applied to saline aquifers in Sacramento Basin. Results showed that applying only hydrodynamic considerations could lead to the wrong choice of a storage site because such a site, even with high permeability and porosity, could lead to losses due to geochemical reactions and microbial interactions. By including the weighting factors and reactions, the site that ranked highest was one that could allow sufficient storage of hydrogen, have a reasonable productivity index, while minimizing loss due to geochemical and microbial reactions. The novelty of this work lies in developing a site selection approach that considers the geochemical and microbial interactions when ranking sites for UHS. Such a workflow will close a significant gap in site selection because geochemical and microbial reactions are essential aspects of UHS-PM.
Deploying Downhole Compression Technology to Enhance Gas Production and Reserves in Mature US Gas Field
Authors: Nader Lukas , Biddick David , Sellers Christopher , Young Cole , Chen K-C , Schoepf Virginie , Abbassi Linda 
Published: September 2024

Abstract
In order to unlock the untapped natural gas potential in the United States, it is crucial to implement innovative solutions. This paper focuses on the challenges associated with increasing gas production and extracting liquids from wells with high liquid content. It provides an overview of the process for gathering reliable data from below the ground, explains the main components of the Subsurface Compressor System (SCS), and showcases the results of using this system to rejuvenate an underperforming well. The paper addresses the challenges of gas production and liquid removal, with a particular focus on collecting downhole data, SCS components, and practical outcomes. Innovative instruments and simulations of multiphase flow were used to determine the best depth for the compressor setting. Specialized pressure tests were conducted to validate the system's capacity to deliver, confirming the necessity for a tailored compressor design.