bluuebunny/crossref_metadata_2025_split huggingface dataset:
Understanding the Impact of Field Development and Changing Fluid Compositions on Corrosion Inhibitor Selection and Performance
Authors: Kirkpatrick Alistair , Reid Melanie , Machray David , Adelusi Adedamola 
Published: June 2014

Abstract
Corrosion inhibitor chemicals are an established successful means of protecting oil and gas producing assets from damage caused by internal corrosion.1,2 Over life of field, these assets will often have to operate under significantly different conditions compared to the original basis of design. Long term processes such as increasing water production and the break-though of injection water in producing wells typically result in a gradual change in system conditions and fluid compositions. Alterations or additions to the system, such as through brown-field development or addition of a subsea tieback, can result in significant and rapid changes to system conditions and fluid compositions.
Corrosion modelling software is often used to predict how these changes will affect the severity of the corrosion risk in the system.3 Although useful in predicting the anticipated corrosivity of the fluids, the models do not adequately take into account the effect which these changes may have on the corrosion inhibitors used to protect the system. Factors such as brine composition can have a minor influence on predicted corrosion rate but a significant effect on inhibitor performance; other factors such as composition of the hydrocarbon phase may dramatically influence inhibitor performance but are not accounted for in standard corrosion modelling software.
This paper describes a laboratory study evaluating the performance of corrosion inhibitors under North Sea oilfield conditions. The paper details how inhibitor performance is affected by changing brine composition over time as a consequence of injection seawater breakthrough from secondary recovery. The study also describes when the overall hydrocarbon composition is altered, due to commingling of fluids in the topsides process as a result of a new subsea tieback to a gas-condensate field being brought on-line. The data presented demonstrates the importance of evaluating the suitability of a corrosion inhibitor under both current conditions and potential future conditions when selecting the most suitable inhibitor for the application. It also highlights that changes in certain factors which do not significantly change fluid corrosivity as predicted by corrosion modelling, such as brine and hydrocarbon composition, can have a significant detrimental effect on corrosion inhibitor performance. Finally, the work reinforces the assertion that inhibitor revalidation is a key requirement, whether system conditions change gradually, for example with injection water break-through or instantaneously through drilling and production of new wells.
The Challenges Associated with the Development and Application of Oil and Gas Corrosion Inhibitors
Authors: Jenkins Alyn 
Published: June 2014

Abstract
In many oil and gas fields around the world, hydrocarbons are being extracted from fields that have very severe system conditions. It is now commonplace for new oil and gas fields constructed with carbon steel piping to operate at extremely high temperatures (&gt;150°C) and it is also normal for fields to produce gas that contains CO2 or H2S in excess of 20 mol%. Consequently, corrosion inhibitors are now required to be effective under very harsh operating conditions. However, these are not the only challenges that corrosion inhibitor developers need to overcome. Corrosion inhibitors are also required to mitigate many diverse forms of corrosion including pitting, under-deposit, galvanic, top-of-line and preferential weld corrosion.
Corrosion inhibitors used in oil and gas production are normally only effective in preventing sweet or sour corrosion. However, in aging assets corrosion inhibitors may also be required to control corrosion due to the presence of oxygen and many traditional inhibitors are simply ineffective when oxygen is present. Furthermore, local environmental regulations restrict what corrosion inhibitors can be used in certain geographic locations. Finally, oil and gas fields operating in deepwater environments provide additional complexities with respect to the deliverability of the corrosion inhibitor to the subsea injection location.
This paper examines the many challenges the industry now faces in developing corrosion inhibitors for new assets, aging assets and deepwater fields. The paper also details the factors that can have a negative effect on inhibitor performance. The paper discusses the restrictions regarding what inhibitor chemistries can be used as a result of environmental regulations and operator preferences. The problems associated with monitoring corrosion inhibitor performance in the field and the considerations required before deploying an inhibitor are also explored.
Passivation of Titanium Alloy with Aminopolycarboxylic Acid-Based HF Acid Fluid
Authors: Lynn Pascarella Natalie , Reyes-Garcia Enrique. A. 
Published: June 2014

Abstract
Exposure of a titanium (Ti)-based alloy to a hydrofluoric (HF) acid-containing fluid can result in corrosion of the alloy and potentially complete dissolution, depending on the temperature and HF acid concentration. The demanding conditions encountered in harsh environments, such as geothermal and high-pressure/high-temperature (HP/HT) wells, require suitable treatment fluids that can be used to remove wellbore scale or accumulated minerals in the near-wellbore (NWB) area. The use of HF acid fluids can then preclude the effective treatment of such formations unless corrosion can be managed. There is no known effective corrosion inhibitor that can be used in conjunction with HF acid on Tialloys. This paper presents findings that can provide advantages for the design of appropriate corrosion inhibitors for these alloys, and similarly, HF acid-sensitive metallurgies. A HF acid-containing fluid based on an aminopolycarboxylic acid (APCA)chelant has the ability to significantly prevent and even minimize the corrosive effects of such fluid on Ti. The chemical combination of chelant/HF acid and conventional corrosion inhibitor plays a functional role in the prevention of the complete corrosion of Ti alloys in the presence of HF acid. Suitable chelant concentrations range up to 0.6 mol/L, corrosion inhibitor loadings up to 4% w/v, up to 2%HF acid concentration, and a pH of 1 to 4. Corrosion loss screening spanned 250 to 300°Fwith APCA and HF acid and up to 375°F with low to no HF acid in the fluid, and specimens treated using an inhibitor suitable for hydrochloric (HCl) acid-based fluids were protected for up to 4 hr. Reasonable corrosion rates less than 0.05 lbm/ft2 were obtained based on the pH, temperature, and HF acid concentration, and to a lesser degree, the amount of chelant. The Ti specimens suffered from pitting, and this was the major negative effect observed. Notably, the use of a conventional yet inhibited HCl/HF acid fluid corroded and dissolved the specimen, unlike all the tests where the chelant/HF acid combination was used. The specimens were analyzed using scanning electron microscopy/energy dispersive X-ray spectroscopy (SEM-EDS) and surface elemental mapping, and the spent fluids were analyzed for dissolved ions (ICP); such analyses serve to elucidate the effects of the chelant and HF acid role in passivating the surface of the alloy.
Numerical Prediction of Reservoir Souring Based on the Growth Kinetics of Sulfate-reducing Bacteria Indigenous to an Oilfield
Authors: Sugai Yuichi , Owaki Yukihiro , Sasaki Kyuro , Kaneko Fuminori , Sakai Takuma 
Published: June 2014

Abstract
Seawater and/or brine injection for oil recovery is frequently accompanied by souring because such water contains sulfate mainly sourced by the growth of sulfate-reducing bacteria (SRB). The mechanisms of reservoir souring vary depending on reservoir conditions such as species of SRB, organic substances that become nutrients for SRB and temperature at what different specie can survive.The purpose of this study is to predict the reservoir souring in an oilfield in which brine injection is planned. For this purpose, chemical and microbiological analyses of the oilfield brine, kinetic studies of the growth of SRB indigenous to the brine, and numerical simulation studies on the reservoir souring in the oilfield have been performed.
Several kinds of organic substances as carbon donors that can be nutrients for SRB were found in both production and injection brine collected in the oilfield. Desulfonosporus sp., Desulfobulbus propionicus and Desulfomicrobium thermophilum were the types of SRB that were found in both brine samples by genetic analyses of DNA extracted from them. Bacterial cell number of SRB in the injection brine was ten times larger than that in the production brine. In addition, the most active growth of SRB was found in the injection brine supplemented with ethanol, therefore, the SRB inhabiting the injection brine was assumed to grow dominantly and generate hydrogen sulfide using sulfate and ethanol in the reservoir. On the basis of this mechanism, an equation that calculated growth rate of the SRB was derived with three variables: temperature, concentration of sulfate, and concentration of ethanol from the results of incubation experiments using the injection brine.
A numerical simulator including the growth rate equation for the SRB was constructed by modifying a simulator of Microbial enhanced oil recovery. The SRB grew and generated hydrogen sulfide around the injection well where temperature was decreased to &lt;50 °C by injected brine. The results of the numerical simulation suggested that severe reservoir souring doesn't occur by the brine injection in the oilfield. Furthermore, the numerical simulation suggested that SRB generates H2S only around the injection well because of a temperature drop there, therefore, the reservoir souring can be prevented more surely by heating up the injection brine to 50 °C, or reducing ethanol in the injection water.
High Resolution Real-Time Thickness Measurement of Internal and External Casing Anomalies with Ultrasonic Scanner Tools
Authors: Tello Lucio N. , Azuaje Dimas C. , Tran Dung 
Published: June 2014

Abstract
The internal and external casing condition is an important part of well integrity evaluation. The public is concerned with environmental issues at sea and on land. In areas where shale exploitation is in full swing, the protection of the underground aquifers is of concern. Tools with increased resolution in corrosion and thickness evaluation are being upgraded to meet these challenges.
Ultrasonic scanning tools measure casing thickness by inducing a resonance in the casing in the thickness-mode. At the same time, they measure the cement acoustic impedance at higher radial and vertical resolution than standard CBL and sector tools. Traditionally, the thickness measurement is delivered after computing the resonant frequency of the pipe from the raw waveforms telemetered to the surface via the communication system. This method is fine except there is a time delay between the acquisition and the final delivered thickness log and map. Another disadvantage of this method is that in order to cover the pipe circumference for thickness, the logging speed needs to be reduced during acquisition.
A modified Digital Fourier Transform algorithm implemented in the ultrasonic radial scanner tool improves the circumferential and vertical coverage over previous methods while extending the thickness measurement range, resolution and accuracy. External corrosion is evaluated by ultrasonically measuring the pipe ID and adding it to the thickness. The algorithm is performed by the down-hole tool at high speed and resolution, covering the pipe in both circumferential and vertical dimensions, in real time and at normal logging speeds, thus saving operation and rig time.
Log examples from test wells constructed to simulate internal and external corrosion, as well as results from field testing corroborate the methodology and the algorithm. The ultrasonic radial scanner with real time thickness (RTT) capability gives a higher resolution thickness measurement and an improved internal and external corrosion evaluation.
Corrosion Management – An Overview of the Corrosion Control Process in OMV Petrom
Authors: Nicolae I. , Firu L. S. 
Published: June 2014

Abstract
Corrosion is causing partial or total destruction of the material in general, and of metals in special due to a reaction with the environment. This destruction is in fact a natural process because of the metals in processed form, have a high energetic level and there is a normal tendency to revert back at initial natural form as oxides in ores.
In the oil and gas industry, down hole pumps, tubing, sucker rods, pipelines and surface facilities equipment made by carbon steel are susceptible to corrosion. Corrosion is caused by the presence of CO2 (sweet corrosion), H2S or organic acids (sour corrosion).
Today applying corrosion inhibitor is a common practice in OMV Petrom. The application of inhibition on the large areas has been implemented since 2007 as part of modernization project in which more than 5000 wells were modernized. This included: the implementation of new artificial lift design and installation of new tubing, new pumps following API standards, corrosion inhibitor injection, dosing skids and optimization of production parameters. At the same time Corrosion Monitoring Devices (DMC) were installed in 10% of injection points. Appropriate chemical trucks for filling up of dossing skids and batch treatments assurance were acquired as well.
This paper shows an overview of corrosion management in OMV Petrom, achievements and benefits of the projects implemented in OMV Petrom in last years, starting with 2005 till today, where Main Time Between Failures (MTBF) increase 8, 5 times in comparison with 2005. The corrosion inhibitor injection process is monitored and optimized continuously keeping corrosion rate under control. Continuous optimization means: coupon and failure analysis, continuous inhibition or batch treatment, adjustment of dosage, new corrosion inhibitor screening considering specific environment and requirements, introducing of new chemistry for tubing carbon steel and new artificial lift design considering corrosion resistant materials etc.
A Selection Methodology for 13Cr-Type Alloy Oil Country Tubular Goods
Authors: Caldwell Eric , Zhang Hugh , Goodman Lindsey 
Published: June 2014

Abstract
Significant interest exists in the deployment of 13Cr martensitic stainless steels in offshore oil and gas projects. Several grades of 13Cr exist, with the seemingly negligible variations between their chemistries and fabrication processes. The different grades perform dramatically differently, especially regarding cracking resistance in sour or chloride-containing environments. Determination of the proper 13Cr grade for sour service involves the investigation of domain diagrams, and often requires further fitness-for-service testing. However, the validity of each domain diagram for only one chloride concentration or content greatly limits their practicality for selecting 13Cr, thus impeding the ability to determining if fitness-for-service testing should be performed and its potential outcome. Therefore, an empirical model compiled from fitness-for-service data and supported by oilfield experience led to the development of a resource tool designed to provide quick validation of fitness-for-service test results, increasing the efficiency of decision-making for 13Cr selections. Also, this paper summarizes the pros and cons of different 13Cr OCTG alloys, in regards to the mechanical strengths and performances in sour/non-sour conditions, high chloride levels, low pH values and presence of CO2. Specifically noted are the H2S partial pressures in excess of NACE MR 0175 limits where 13Cr materials can be successfully utilized.
Investigation of Noninvasive Healing of Damaged Piping System using Electro-Magneto-Mechanical Methods
Authors: Mukherjee Debanjan , Zaky Zeyad , Zohdi Tarek I. , Salama Amgad , Sun Shuyu 
Published: June 2014

Abstract
Virtually all engineering applications involve the use of piping, conduits and channels. In the petroleum industry, piping systems are extensively employed in upstream and downstream processes. These piping systems often carry fluids that are corrosive, which leads to wear, cavitation and cracking. The replacement of damaged piping systems can be quite expensive, both in terms of capital costs, as well as in operational downtime. This motivates the present research on noninvasive healing of cracked piping systems. In this investigation, we propose to develop computational models for characterizing noninvasive repair strategies involving electromagnetically guided particles. The objective is to heal industrial-piping systems noninvasively, from the exterior of the system, during operation, resulting in no downtime, with minimal relative cost. The particle accumulation at a target location is controlled by external electro-magneto-mechanical means. There are two primary effects that play a role for guiding the particles to the solid-fluid interface/wall: mechanical shear due to the fluid flow, and an electrical or magnetic force. In this work we develop and study a relationship that characterizes contributions of both, and ascertain how this relationship scales with characteristic physical parameters. Characteristic non-dimensional parameters that describe system behavior are derived and their role in design is illustrated. A detailed, fully 3-dimensional discrete element simulation framework is presented, and illustrated using a model problem of magnetically guided particles. The detailed particle behavior is considered to be regulated by three effects: (1) the field strength (2) the mass flow rate and (3) the wall interactions.
Snorre In-depth Water Diversion Using Sodium Silicate - Large Scale Interwell Field Pilot
Authors: Skrettingland Kjetil , Dale Elisabeth Iren , Stenerud Vegard Røine , Lambertsen Anne Marie , Kulkarni Kari Nordaas , Fevang Øivind , Stavland Arne 
Published: June 2014

Abstract
Here we report on in-depth water diversion using sodium silicate to increase oil recovery at the Snorre field, offshore Norway. A comprehensive qualification program revealed that the onset of gelation can be controlled; this was demonstrated in realistic core flood experiments as well as in a single well injection pilot. This paper highlights key design, response measurement plan and operational experiences from a large scale interwell field pilot of sodium silicate injection in a reservoir segment at the Snorre field on the Norwegian Continental Shelf. The operation of injecting 113 000 m3 preflush, 240 000 m3 sodium silicate and 49 000 m3 postflush was performed from June to October 2013. The goal is to create an in-depth restriction between a subsea water injection well and a platform oil producer with approximately 2 000 m well spacing, and thereby improve the reservoir sweep by water injection.
To perform the field pilot a 35 000 ton shuttle tanker was converted to a well stimulation vessel with the necessary equipment to accommodate a higher number of people, a desalination plant, storage and mixing equipment and high pressure pumps. The vessel was connected directly to a subsea water injection well and injected during a period of 5 months. The chosen design was to (a) soften the formation water by a KCl preflush, (b) control the gelation kinetics using HCl acid as activator, mixed into the diluted silicate solution and (c) displace the silicate solution by a KCl postflush followed by seawater injection.
The pilot injection operation is completed, and the displacement of the sodium silicate with following seawater injection to the planned position for in-depth plugging is still on-going. The operational success criteria of proving ability to perform large scale transport, mixing and injection of sodium silicate from a shuttle tanker directly into a subsea well with no near wellbore plugging is met. Future production response will reveal if the success criteria of in-depth plugging, improved reservoir sweep and decrease in water cut will be met.
Use of Carbon Dioxide and Hydrocarbon Solvents During the Method of Steam-Over-Solvent Injection in Fractured Reservoirs for Heavy-Oil Recovery From Sandstones and Carbonates
Authors: Naderi K.. , Babadagli T.. 
Published: June 2014

Summary
Because of low efficiencies and the high cost of the individual injection of steam and solvent for heavy-oil recovery, their hybrid applications have gained significant attention recently. Although numerous laboratory studies exist and there are a considerable number of field projects for sandstone environments, fractured carbonates lack technologies to drain matrix oil efficiently. An alternative-method injection of solvent and steam was proposed and tested earlier (Babadagli and Al-Bahlani 2008). This process applies steam initially to condition the matrix oil for succeeding solvent injection and steam reinjection to retrieve solvent in the matrix and to recover additional upgraded oil. The present study uses carbon dioxide (CO2) as a solvent and compares it with hydrocarbon solvents in this type of application. To clarify the physics of the process and to test the applicability of the method for different reservoir and injection conditions, we conducted a series of experiments by first injecting steam, followed by CO2 injection. In the third cycle, steam was injected again to produce upgraded oil in the matrix. The experiments were performed under static conditions (soaking sand and carbonate samples in steam or CO2 chambers) at different temperatures and pressures. CO2 is shown to be a reasonable alternative for hydrocarbon solvents in such a process in terms of cost and benefits by reducing the solvent expenses, keeping the oil-production levels, and disposing of a greenhouse gas.
Well Completions and Profitability: A Horn River Shale Case Study
Authors: Ross C. R. , Anderson D. M. , Stephens C. P. , Virues C. 
Published: June 2014

Abstract
The profitability of a well in an unconventional play is significantly influenced by its completion. It is widely understood that tighter rock needs more stimulation to economically recover hydrocarbons. However, how does one know if a well is being over-stimulated (fracture area created does not justify cost incurred) or under-stimulated (lost potential/profitability in productivity from a well's limited contact to the formation)?
The objective of this paper is to develop and demonstrate an efficient workflow that will help stakeholders make better decisions in the area of completion planning. The workflow utilizes information from fracture modeling, production data analysis, and project economics to quantify the relationship between the key input parameters of the well completion (e.g. pumping rate, proppant and fluid pumped) and expected profitability expressed in net present value (NPV) terms. As a secondary objective, the case study demonstrates that a probabilistic approach (Monte Carlo Simulation) can be used to efficiently arrive at a consistent conclusion to the primary workflow. The output of the probabilistic model includes P90/P50/P10 production and net cash-flow forecasts, from which distributions of NPV can be obtained.
This workflow is intended to help engineers compare profitability among different completion options. A shale gas field example is presented to illustrate the methodology.