bluuebunny/crossref_metadata_2025_split huggingface dataset:
Profiling the Production Performance of Five HPHT Gas Condensate Wells Drilled and Completed with High-Density Cesium Formate Fluids in the Brent Group Formations of the Kvitebjørn Field
Authors: Downs J. D. , Fleming N. 
Published: February 2020

Abstract
This paper provides insights into the long-term production performance of a set of five HPHT wells drilled and completed with SG 2.0 cesium formate fluids across the entire sequence of gas-filled Brent Group reservoir formations of the Kvitebjørn field during the period 2004/5.
Three of the wells were completed in open hole with screens and the other two with cemented and perforated liners. All of the wells cleaned up naturally during production start-up. Well logs run in the first series of wells drilled and completed with cesium formate fluids provided enhanced reservoir information indicating improved reservoir quality which translated into a 33% increase in the Hydrocarbon Pore Factor (HCPF). After a year of production from these wells a new updated reservoir evaluation, factoring in the improved reservoir quality and more reservoir volume, increased the overall Kvitebjørn recoverable gas reserves by 50% to 79.97 GSm³ of gas and 30.13 million Sm³ of condensate. As a result of this evaluation the expected recoverable reserves for the first five production wells drilled in 2004/5 rose from 32.7 GSm3 to 48.3 GSm3 for gas and from 12.3 MSm3 to 14.8 MSm3 for condensate.
Apparent reductions in well productivity indices (PI) of 20-80% were measured in the first 5-7 years of production. The PI reductions could have resulted from a combination of scaling, condensate banking, reservoir compaction or even problems with the PI estimations. One of the wells with a liner completion was re-perforated twice (in 2012 and 2015) and another well with a screen completion was perforated through blocked screens in 2015, but the remaining three wells have continued to produce without intervention for 14 years. The cumulative gas production from the five wells up to October 2018 stood at 60.1 GSm3, which is already 24 % higher than the mean total recoverable reserves predicted in the 2006 reserves evaluation and almost double the figure anticipated in the original 2004 field development plan. The cumulative condensate production over the same time stood at 20.4 MSm3, which is 38 % higher than the mean total recoverable reserves predicted in the 2006 reserves evaluation and almost double the figure anticipated in the original 2004 field development plan.
In laboratory formation damage tests conducted at 150°C the oil permeability of a Kvitebjørn reservoir core plug flooded with a sample of the cesium formate drilling fluid recovered from the field after use in all five wells was reduced by 65% from 29 mD to 10.2 mD. This very valuable test may now allow a retrospective evaluation of the predictive value of that particular laboratory-based return permeability test method used to assess the formation compatibility of that formate fluid twelve years ago.
A Review of Organic Acids Roles in Acidizing Operations for Carbonate and Sandstone Formations
Authors: Alhamad Luai , Alrashed Ahmed , Al Munif Eiman , Miskimins Jennifer 
Published: February 2020

Abstract
Hydrochloric acid (HCl) is the acid of choice for acidizing operations in most carbonate formations and is the base acid commonly paired with others such as hydrofluoric (HF) in most sandstone applications. However, high dissolving power, high corrosion rate, lack of penetration, and sludging tendency coupled with high temperature can make HCl a poor choice. Alternatively, weaker and less corrosive chemicals such as organic acids can be used instead of HCl to avoid these issues. The objective of this paper is to provide an intensive review on recent advancements, technology, and problems associated with organic acids. The paper focuses on formic, acetic, citric, and lactic acids.
This review includes various laboratory evaluation tests and field cases which outline the usage of organic acids for formation damage removal and dissolution. Rotating disk apparatus results were reviewed to determine the kinetics for acid dissolution of different minerals. Additional results were collected from solubility, corrosion, core-flooding, Inductively Coupled Plasma (ICP), X-Ray Diffraction (XRD), and Scanning Electron Microscope Diffraction (SEM) tests.
Due to their retardation performance, organic acids have been used along with mineral acids or as a stand-alone solution for high-temperature applications. However, the main drawback of these acids is the solubility of reaction product salts. In terms of conducting dominant wormhole tests and low corrosion rating, organic acids with low concentrations show good results. Organic acids have also been utilized in other applications. For instance, formic acid is used as an intensifier to reduce the corrosion rate due to HCl in high-temperature operations. Acetic and lactic acids can be used to dissolve drilling mud filter cakes. Citric acid is commonly used as an iron sequestering agent.
This paper shows organic acid advances, limitations, and applications in oil and gas operations, specifically, in acidizing jobs. The paper differentiates and closes the gap between various organic acid applications along with providing researchers an intensive guide for present and future research.
Downhole Scales Associated with October Field Formation Waters and Water Injection Using a Shallow Aquifer
Authors: Askar Mohamed , Abdallah Ahmed , Gad Ibrahim 
Published: February 2020

Abstract
Gulf of Suez Petroleum Company (GUPCO) has been producing from October field since 1977. Currently the total daily production from the field is 80 MBFPD with average water cut 76 %. October field contains four formations with extremely different characteristics. Each formation has unique combination of lithology, downhole conditions, and formation water chemistry.
Through the whole life of October field, more than 300 downhole scale samples were collected, in addition to more than 180 wellhead water samples were completely analyzed. This set of data can be used to categorize formations according to their capability to deposit a certain type of inorganic scale. After reservoir depletion, sea water had been used in water injection. By the time, field needs changed and a shallow water aquifer replaced sea water in supporting some reservoirs. Several compatibility tests and scale tendency calculations had been done before using the shallow aquifer (Zeit formation).
Each well was experiencing different production conditions which dedicated deposition of certain types and amounts of inorganic scale. Scale deposition depth depended on the degree of mixing between incompatible waters, and the introducion of pressure or temperature changes along wellbore. After water breakthrough, some pressure-supported wells faced some carbonate scale deposition due to the dissolved carbon dioxide in Zeit water. Generally, Zeit formation can be used as a good alternative for sea water in water injection projects in Gulf of Suez area. Some formations contain a self-scaling water which has the ability to deposit sulfate and sulfide scales without mixing with any other water e.g. Nubia formation water. Sea water cooling, in offshore wells, usually forces scale deposition at shallow depths especially against the downhole safety valve and Christmas tree valves.
This study is expected to be a good tool in recommending scale inhibition methods or products for new wells drilled in October field or any analogous field. This study can compensate for the gap between commercial scale prediction software and actual scale deposits, as most current software products rely only on thermodynamic equations for surface-collected water samples.
Perforating Crushed Zone Fracture Mechanism
Authors: Craddock G. G. , Rios Federico 
Published: February 2020

Abstract
Perforations are used to flow hydrocarbons into a well. Impeding that flow are damaged zones from drilling and the crushed zone lining the walls of perforation tunnels into the rock. In addition, charges can affect a region beyond the crushed zone. This region is termed the "fracture damage zone," and the nature of this region is examined in this paper. The fracture damage zone is the area where the concrete model shows altered effects. This region of damage is not necessarily failed, but is the most likely region of fracture. This work discusses the use of a shock hydrocode to delineate this region. Because the hydrocode is a continuous code, specific fracture paths are not predicted. The code is run for big hole (BH). deep penetration (DP), and fracture (Frac) shaped charges. The damaged region is compared for the types of shaped charges. Simulation results indicate that the region of fracture damage follows the bow shock. This semicircular bow shock region continues propagation after the jet has stopped, but eventually diminishes outward from the jet origin. Generally, the BH charge has a wider damage region than the DP charge, with the DP charge damage region being narrower and deeper than the BH (because of the depth of penetration). The damage zone of the Frac charge is between those of the BH and DP charges. In addition, the damaged region may not be sufficiently affected to actually create failure caused by fractures. "Distance" to the fracture limit is characterized. This ready-to-fracture region is discussed in terms of making it a failed fracture region by external influences, such as propellant stimulation.
MWD and MPD System Combination Successfully Manages Ultra-High LCM Concentrations and Cement Slurries in Loss Scenarios
Authors: Valerio Alexander , Carvalho Gabriela Luisa 
Published: February 2020

Abstract
Whilst drilling the 12 ½" and 8 ½" sections on a HPHT field in the North Sea, fluid losses were encountered which required the pumping of high concentration Loss Circulation Material (LCM) as well as multiple ‘through the bit’ cement squeezes. The reservoir had been under production for many years and was now at a point where it had significantly depleted and the formation was very delicate, making it easily subjected to fracturing. Losses were expected to be an upcoming challenge as the mud weight window was so narrow and due to the HPHT rating of the offshore reservoir and the fractured nature of the geology, this posed as a serious risk that required pre-planned mitigation.
The ability to pump ultra-high LCM concentrations was discussed in pre-planning as being one of the key mitigation strategies to stemming losses. However, it was thought that pumping LCM would block a typical MWD pulser due to the narrow geometries of the flow paths within. Successful onshore testing was conducted prior to drilling operations to prove that the MWD pulser selected had the ability to permit the flow of ultra-high concentrations of LCM. A closed loop system was created onshore and LCM with concentrations up to 420kg/m3 (147lbs/bbl) was pumped through the MWD tool without blocking it up and with full functionality throughout. This gave the operator the confidence to pump LCM through the MWD tools, if required in the field.
The use of an MPD (Managed Pressure Drilling) system was also required to keep the equivalent circulating density within the tight mud weight window by maintaining a constant bottom-hole pressure through the application of Surface Back-Pressure (SBP). This was critical as the well, when static, was underbalanced. The incorporation of MPD also gave the operator the ability to ‘squeeze’ LCM/cement into the well and formation by applying surface back pressure during ‘through the bit’ LCM/cement jobs. During field operations, the operator did go on to pump a 320 kg/m3 (112 lbs/bbl) LCM pill through the MWD tool without plugging during a loss scenario. Pumping LCM through the MWD tool reinforced the formation and enlarged the mud weight window from &lt;0.01sg to 0.03sg allowing operations to continue. In addition, muliple "through the bit" MPD LCM/cement squeezes were conducted on two wells in the same field with no negative effect on any of the MWD tools.
The partnership between the MWD and MPD systems formed a key part of the losses management. The MWD system could identify exactly what downhole pressure losses were seen at, which was then transmitted by the pulser to the surface. The MPD system would then use an algorithm based calculation to apply the exact required SBP to maintain a constant bottomhole pressure, that was within the mud window. This provided the operator a safe and efficient solution to continue to the target depth in a very challenging narrow margin well.
Laboratory Evaluation of Mud Systems for Drilling High Clay Shales in Dynamic Conditions: Comparison of Inhibitive Systems
Authors: Konate Nabe , Magzoub Musaab , Salehi Saeed , Ghalambor Ali , Mokhtari Mehdi 
Published: February 2020

Abstract
Wellbore instability is caused by the radical change in the mechanical strength as well as chemical and physical alterations when exposed to drilling fluids. Unscheduled events that are related to wellbore instability account for more than 10% of the drilling cost, which is estimated to one billion dollars per annual cost. Understanding shale-drilling fluid interaction plays a key role in minimizing drilling problems in unconventional resources. The need for providing a more suitable drilling fluid system for drilling operations in unconventional resources is growing. The major consequences of improper fluid selection include bit-balling, hole sloughing, and most importantly low drilling rates. This study will evaluate the effect of different inhibitive drilling fluid systems on shale drilling performance. The mud systems use in this study include cesium formate, KCl based mud systems, and a conventional water-based mud. The conventional water-based mud is used as reference fluid. An innovative HPHT drilling simulator is used to perform real-time drilling operations on cylindrical shale core samples obtained from the Tuscaloosa Marine Shale (TMS). The process involved simulating real-time drilling operation at downhole conditions where different fluids served as drilling fluid. A comparative analysis of the impact of each drilling fluid systems on the drilling performance as then performed. The analysis focused on drilling parameters such as rate of penetration, torque, and friction factor during drilling. This paper evaluates the compatibility between different fluid systems and shale formations. The paper also provides an overview of the effect of the inhibitive mud systems on drilling performance. The inhibitive muds systems (KCl based fluids and cesium formate) provided improved drilling performance compared to conventional water-based mud.
The Development of the Trends in Formation Damage Removal Technologies in Sandstone Reservoirs
Authors: Maltcev Andrei , Shcherbakov Georgii 
Published: February 2020

Abstract
The article describes the main ideas of the integrated approach to the use of matrix-stimulation methods in the oilfields with sandstone reservoirs. LLC Gazpromneft scientific and technology center as the basis of the project "Optimal matrix stimulation methods" undertook the joint study. The project objective is to increase the efficiency of matrix stimulation by introducing advanced techniques for automized well selection and calculating the design of acidizing based on mathematical modeling.
Enhancement of Water Imbibition in Shales by use of Ketone Solvent
Authors: Argüelles-Vivas Francisco J. , Wang Mingyuan , Abeykoon Gayan A. , Okuno Ryosuke 
Published: February 2020

Abstract
This paper presents an application of 3-pentanone, a symmetric short ketone, to enhance the water imbibition in coreflooding of fractured carbonate cores. 3-Pentanone was tested in two ways: 1.1-wt% 3-pentanone solution in reservoir brine (3pRB) and pure 3-pentanone (3p) as a miscible solvent. It was presented previously that 3p is a mutual solvent for oil and water, and can rapidly change the rock wettability to strongly water-wet with its electron-rich oxygen atom through the oil and water phases. The main objective of this research is to investigate how the initial water saturation in the matrix affects the imbibition of 3pRB or 3p from the fracture and the resulting recovery of oil from the matrix.
The experimental results were analyzed in terms of material balance (mass and volume) with simplifying assumptions. This analysis enabled to estimate how much of the injected components were imbibed into the surrounding matrices from the fracture and the relative contribution of the injected components to displacing oil in the matrix.
For the injection of 3pRB, the oil recovery was consistently greater when there was an initial aqueous phase in the matrix. While the presence of an initial aqueous phase did not affect the imbibed fraction of the injected 3p, it made it more effective for 3p to enhance the oil displacement by water in the matrix. For example, 87% of the oil recovered from the matrix was displaced by water (the rest by 3p) for the coreflood with an initial water saturation of 31%.
The injection of pure 3p showed that a larger amount of oil was recovered from the matrix with the presence of an initial aqueous phase in the matrix. The oil recovery mainly came from the displacement of oil by 3p in the matrix with a minor contribution of water. Results for the 3pRB and 3p injections indicate collectively that 3-pentanone was more effective in enhancing oil recovery when an aqueous phase was initially present in the matrix.
Quantitative Analysis of the Effect of Perforation Interaction on Perforation Stability Using the Finite Element Method
Authors: Araki Naoto , Morita Nobuo 
Published: February 2020

Abstract
Although a well has hundreds of perforations, a single perforation is normally used for perforation interaction analysis assuming the perforations are shot symmetrically and the stress state around a perforation is symmetric in both vertical and horizontal directions. However, for the single/double spiral perforations shot in inclined wells, no vertical and horizontal symmetry surfaces exist. Required elements for multi-perforation model are more than 10,000, which results in complex mesh generation and long computation time. This study investigates perforation interaction to find the optimum perforation design which yields the highest productivity while maintaining mechanical stability.
Introduction of Newly Deployed Wellbore Cleaning Technique
Authors: Al-Tammer Hasan , Al-Ghafli Hashem , Davidson Brett , Abouakar Ahmed 
Published: February 2020

Abstract
It is common knowledge that over its life-cycle an oil producer or water injector may experience a reduction in near-wellbore permeability or overall fluid connectivity to or from the reservoir from in-wellbore impediments that negatively impact productivity or injection. Such permeability reductions or fluid connectivity losses are often related to near-wellbore damage or ‘skin’ or in-well damage induced by fill, scales, waxes, asphaltene or other blocking mechanisms. In recent years an increasing number of coiled tubing ("CT") stimulation and cleanout interventions has led to the advancement of downhole tools focused on remediating such damage mechanisms. One such development that has been successfully deployed to re-establish water injection rates for reservoir pressure support in oil field production operations is a multi-directional, cavitational-based fluid pulsing tool that provides a hydro-mechanical means to both remove detritus materials from the immediate wellbore but also stimulate the near-wellbore region.
Comparison of Various Particle Size Distribution Measurement Methods: Role of Particle Shape Descriptors
Authors: Roostaei Morteza , Soroush Mohammad , Hosseini Seyed Abolhassan , Velayati Arian , Alkouh Ahmad , Mahmoudi Mahdi , Ghalambor Ali , Fattahpour Vahidoddin 
Published: February 2020

Abstract
Sieve analysis, sedimentation and laser diffraction have been the methods of choice in determining particle size distribution (PSD) for sand control design. However, these methods do not provide any information regarding the particle shape. In this study, we introduce the application of Dynamic Image Analysis (DIA) to characterize particle sizes and shape descriptors of sand bearing formations.
Dynamic Image Analysis, an advanced method of particle size and shape characterization, along with other PSD measurement methods, including sieving combined with sedimentation, and laser diffraction, was utilized to study size and shape variations of 372 unconsolidated formation sand samples from North America, Latin America, and the Middle East. Different methods were compared for the estimation of PSD and fines content, which is important for sand control design.
Through minimizing the sampling and measurement errors, the deviation between different PSD measurement techniques was attributed solely to the shape of the particles and the amount of fine fraction. For fines content measurement, the values obtained through Feret Min. parameter values (the minimum size of a particle along all directions) calculated by DIA and sieving measurement are comparable within a 5% confidence band. The deviation between the results of different methods becomes more significant by increasing fines content. Moreover, this deviation increases for less isodiametric grains. The fines and clay content show higher values when measured by any wet analysis. Laser diffraction also tends to overestimate the fines fraction and underestimate silt/sand fraction compared to other dry techniques. By comparing the deviation of the DIA and sieving at standard mesh sizes, an algorithm has been developed which chooses the equivalent sphere sizes of DIA with minimum deviation from sieving.
This study performs several measurements on formation sands to illustrate the real advantage of the new methods over traditional measurement techniques. Furthermore, particle shape descriptors were used to explain the deviation between the results of different PSD measurement methods.
The Efficacy and Tolerability of Ubrogepant for Episodic Migraine: A Systematic Review and Meta-Analysis
Authors: Diao Yun , Yang Hang , Zhou Yang Chun , Du Biao 
Published: February 2020

Abstract
Background: The aim of this review was to evaluate the efficacy and tolerability of ubrogepant in patients with episodic migraine. Methods: We systematically searched PubMed, Embase, MEDLINE, Cochrane Library, and clinicaltrials.gov from inception to JULY, 2019. Randomized controlled trials of the efficacy and/or tolerability of ubrogepant for migraine were included. Meta-analysis was conducted by RevMan 5.3 software. Results: A total of 4 RCTs involving 4 163 patients were included. The meta-analysis showed that there were significant differences in the percentage of subjects with PF, PR, SPF, SPR, sound without phobia, light without phobia and nausea compared with the control group. (RR=1.31,95%CI:1.18~1.45，P<0.00001, RR=1.63,95%CI:1.46~1.82，P<0.00001, RR=1.22,95%CI:1.15~1.29，P<0.00001, RR=1.32,95%CI:1.22~1.42，P<0.00001, RR=1.16,95%CI:1.05~1.27，P=0.002), all the differences were statistically significant. Conclusions: For adult patients with episodic migraine, ubrogepant could effectively abort the acute attack. High-quality, adequately powered RCTs are needed to fully evaluate the efficacy and tolerability of ubrogepant for episodic migraine.