bluuebunny/crossref_metadata_2025_split huggingface dataset:
When To Batch and When Not To Batch: An Overview of Integrity Management and Batch Corrosion Inhibitor Testing Methods and Application Strategies
Authors: Wylde Jonathan J. , Reid Melanie , Kirkpatrick Alistair , Obeyesekere Nihal , Glasgow David 
Published: June 2014

Abstract
Batch corrosion inhibition has been a technique used for many decades. Often, a non-structured philosophy is taken to treat downhole production tubing and pipelines using batch treatment. This results in non-optimal chemistries and application parameters being employed, resulting in dubious protection being provided as part of an integrity management strategy.
Many of the challenges come down to the different types of evaluation techniques in the laboratory for batch corrosion inhibitors. Furthermore, accurate modeling of batch corrosion inhibitor application is not performed and the application parameters are not optimal; this all results in non-efficient or non-effective protection being provided to the steel of the system.
This paper reviews the different types of methodology used to evaluate batch corrosion inhibitors in the laboratory, ranging from the simple copper sulfate displacement method to advanced electrochemical techniques. Subsequently, it illustrates how the laboratory data can be entered into advanced modeling routines to design the most cost-effective and high-performing application. The paper then gives a case history discussing the different approaches that can be taken for testing and application.
The conclusions of this study show how using the most appropriate testing methodology and modeling can contribute to a much more efficient and appropriate chemical integrity management strategy. The conclusions identifythat the chemical application method into the target system is absolutely crucial to success. The lessons learned from this paper can be used by engineers to optimize their integrity management strategies where batch corrosion inhibition is the mainstay tool for control of corrosion.
Halite Scale Formation Mechanisms, Removal and Control: A Global Overview of Mechanical, Process and Chemical Strategies
Authors: Wylde Jonathan J. , Slayer Jubal L. 
Published: June 2014

Abstract
Halite scale has long been a challenge in the oil and gas industry. In recent years there has been a marked increase in the occurrence of this scale type due to the increased development of hotter and deeper gas and gas condensate fields. As the formation of this scale is commonly in the downhole production tubing, it is a challenge to identify and mitigate, so a non- conventional approach has to be taken for removal and control. Furthermore, it is very difficult to replicate the formation of this scale in the laboratory with complex and specific equipment being utilized to replicate field observations.
This paper provides a review of several examples of halite scale formation in the field, detailing the mechanism of deposition and the strategies employed to remove and subsequently prevent reoccurrence. Details are also provided for two different types of laboratory test methods; the first being a simple static test method designed to quickly screen the extent of halite challenge and the suitability of a range of inhibitors. The second laboratory method concerns a novel, dynamic method whose primary aim is to accurately measure and predict the severity of scaling in the field, and then go on to determine the minimum effective dose of inhibitor required to prevent build-up.
The different types of halite inhibitor chemistries are evaluated, including the use of wash water and where this is used in combination with organo-ferrous compounds, as well as more novel polymeric compounds. The paper concludes by providing an insight into the economics of the different types of treatment, namely the use of wash water versus the use of chemical inhibitors and combinations of these two techniques.
Quantifying Increased Corrosion Risks in Chemical Injection Lines and Gas Lift Systems Due to Partial Evaporation Effects
Authors: Bowering Deborah , Goodwin Neil , McCall Matthew , Stalker Robert , Graham Gordon 
Published: June 2014

Abstract
The application of production chemicals downhole via dedicated injection lines or by means of gas lift systems, whilst not new, is becoming more commonplace in the oil and gas industry. The corrosion characteristics of injected chemical formulations in such systems can be complex and require detailed testing to understand the behaviour and assess the potential corrosion risk of chemical formulations under the extreme conditions of temperature and pressure that exist within either of these injection systems.
In the presence of a fast flowing stream of hot gas, the more volatile components can be stripped from the formulated product, resulting in separate condensed vapours and chemical residues. Similarly, low-pressure vapour pockets formed within downhole chemical injection systems due to hydrostatic pressure fluctuations may cause some components of the injected chemical to be evaporated. Materials compatibility tests are commonly conducted using samples of "as supplied" production chemicals However, there is also a risk that different material compatibility/corrosivity characteristics can be induced by the condensed vapours or stripped residues of the production chemicals when compared to the originally applied chemical formulation. Laboratory testing is not commonly conducted to assess this behaviour.
Samples have been prepared and corrosion tests conducted on collected vapours and residues from production chemicals. Distillations were conducted on the neat chemicals to obtain vapours and residues, and corrosion rates were measured on a range of different metallic specimens by conventional electrochemical or coupon weight loss methods. The results of these separated phase corrosion tests were then compared with the corrosion measurements on the original formulations.
The test programme demonstrated that for some of the formulations tested, significantly higher corrosion rates were measured for either the condensed vapours or the distillation residues when compared to the original formulation.
This work highlights the need to carefully consider the possible range of temperature/pressure conditions and gas/liquid phase interactions that will be experienced by injected chemicals within the chemical delivery system. Specifically, there is a need to assess the implications of solvent stripping/evaporation of volatile components. Chemicals that form more corrosive condensed vapours or residues may need to be avoided to prevent equipment failure or a loss of integrity. It is not adequate to simply test the ‘stability’ of a chemical at elevated temperatures, ambient pressure and static conditions; the separation effects within the gas/liquid system must also be considered.
Development of Peracetic Acid (PAA) as an Environmentally Safe Biocide for Water Treatment During Hydraulic Fracturing Applications
Authors: De Paula Renato M. , Keasler Victor V. , Li Junzhong , McSherry Dave , Staub Rich 
Published: June 2014

Abstract
In the past years, unconventional oil and natural gas production has steadily increased in the United States. Driven by the development of new technologies such as horizontal drilling and hydraulic fracturing, shale gas has led to major increases in reserves of oil and natural gas. During hydraulic fracturing, water and chemicals are injected, at high pressure, into the formation to increase the fractures in the rock layer and allow hydrocarbons to flow. Because large quantities of water are used during this process, the need for water treatment and reuse has become critical. Water treatment prevents the introduction of microorganisms in the formation, which can potentially result in problems such as reservoir souring, biofouling and microbiologically induced corrosion (MIC). Additionally, cleaning of produced water reduces the constant demand for fresh water. Based upon these concerns, we have developed an improved formulation of the oxidizing biocide peracetic acid (PAA). To determine the potential use of PAA in fracturing application, we conducted a number of tests in laboratory and field conditions. We found that this improved chemistry shows superior results when compared to other conventional biocides (glutaraldehyde, THPS, etc), including faster and persistent microbial kill, lower corrosivity, water cleanup properties and solids dropout. We also found that PAA had no adverse effects on other chemistries present in the frac fluids, such as friction reducers and scale inhibitors. Additionally, PAA is a "green" chemistry as it breaks down into innocuous components. Altogether, PAA represents an extremely efficient and environmentally safe option for treatment of water used for hydraulic fracturing.
Stability Investigation of Low-Tension Surfactant Floods
Authors: Lu Jun , Pope Gary A. , Weerasooriya Upali P. 
Published: June 2014

Abstract
Classical stability theory can be used to estimate the critical velocity of a miscible flood stabilized by gravity forces. However, stability theory for an ultra-low interfacial tension (IFT) surfactant displacement is not well developed or validated. In this paper, a method for predicting the critical velocity for a surfactant flood is proposed taking into account the microemulsion phase. Vertical upward surfactant displacement experiments were performed and compared with stability theory. The proposed theory and experimental results offer new insight into the behavior of surfactant floods stabilized by gravity forces.
The Effect of Shale Chemistry on Gas Production Decline in Hydraulically Fractured Shale Gas Wells
Authors: Hassanpoor D. , Hayatdavoudi A. , Boukadi F. 
Published: June 2014

Abstract
Shale gas has become an increasingly significant source of natural gas in the United States. It is puzzling to many that most of the shale gas wells decline very rapidly. Our study shows that in hydraulic fracturing of shale-gas wells operators often use "slick water". The "slick-water", as carrier fluid, comprises plain water and some combination of polymer gel, gel breakers, cross-linkers, and surfactant or surfactant/water alone. However, in lessons learned from the oil field personnel and our own years of research and field practice, we see that first Polymers in general upon hydration retain a water layer for a long time, second Shale absorbs or allows this water layer in the shale body under suction (negative) pressure, then, it converts the suction pressure to swelling pressure reaches which closes the micro fractures, and third, to complicate the matters, some surfactants simply disperse the shale-clays. The net effect of these mechanisms is rapid production decline.
One of the most important mechanisms is water absorption. Shale absorbs water due to the capillary effects of micro fractures and the shale-clay potential. However, there is no model to show the relationship among capillary effect, the shale-clay type potential, the morphology of the shale aggregate, and finally the production decline. We propose a model which connects the above mentioned four elements together and shows the way to the root cause of rapid production decline.
Based on the results we conclude: first the proposed model shows a good correlation between the above four elements in terms of shale fractal dimension and the shale hydration index, all used for calculating the excess hydration stress, and second the excess hydration stress accelerates micro fracture closure, hence the rapid gas production decline.
The benefits of our work follows: one is the combined HHI and the shale fractal dimension can be used to optimize the shale hydraulic fracture conductivity toward long term gas production and the other is the correlation offered here shows it to be a better method for measuring the shale-water activity by using the shale characteristics, namely, the shale water content, the Hydration Index, and the shale fractal dimensions.
The Effect of Surfactants on Vertical Air/Water Flow for Prevention of Liquid Loading
Authors: Van Nimwegen A. T. , Portela L. M. , Henkes R. A. 
Published: June 2014

Abstract
From field experience in the gas industry, it is known that injecting surfactants at the bottom of the well can prevent liquid loading. To increase understanding of surfactant selection, laboratory experiments of air-water flow at atmospheric conditions were performed, where two different surfactants (Sodium dodecyl sulfate and Trifoam 820 Block) were added to the water. In the experiments, a high-speed camera was used to visualize the flow and pressure drop measurements were performed. Both surfactants increase the pressure drop at high gas flow rates and decrease the pressure drop at low gas flow rates. The minimum in the pressure drop moves to lower gas flow rates with increasing surfactant concentration. This is related to the transition between churn and annular flow, which is shifted to lower gas flow rates due to the formation of an almost stagnant foam substrate at the wall of the pipe. At high surfactant concentration, it appears the churn flow regime is no longer present at all and there is a transition from annular flow to a regular slug flow. The results also show that both the critical micelle concentration and the equilibrium surface tension are poor predictors of the type and concentration of surfactant required to decrease the pressure drop.
Pore-Size Dependence of Fluid Phase Behavior and Properties in Organic-Rich Shale Reservoirs
Authors: Didar Behnaz Rahmani , Akkutlu I. Yucel 
Published: June 2014

Abstract
Because of commodity pricing, the production from organic rich shales such as Barnett, Woodford, Eagle Ford and Marcellus has shifted significantly away from the dry natural gas window into the more profitable condensate and liquid hydrocarbon (oil) windows. The current production practices, however, are based mainly on field experience of the operators and far from being a methodological approach for an optimized production. This is mainly due to the fact that our understanding of condensation, capillarity and multi-phase flow dynamics in shale reservoirs is at an infancy stage. It is currently not known, for example, if and where the condensation takes place in the reservoir, and what is the impact of the shale matrix on the this phenomenon. In this paper we argue that answering these questions using conventional laboratory measurement techniques is a difficult task because the fluid properties and the phase behavior of the hydrocarbons could be influenced by the nanoporous nature of these rocks.
Monte Carlo simulations are conducted to investigate pure hydrocarbon vapor-liquid coexistence and critical properties under confinement. The results show a pore size dependence of these thermo-physical properties. Phase diagrams generated using ternary (C1, C4, and C8) mixtures under reservoir conditions show a two-phase envelop shift due to pore size dependence. We show the importance of the results performing a shale gas in-place calculation using Ambrose's equation where the equation of state parameters, z-factor, gas formation volume factor, and adsorbed-phase density values are all adjusted for a range of effective pore size. The corrections on the free and the sorbed gas in-place estimates are significant. Furthermore, we predicted reserves from wet gas, condensate, and volatile oil reservoirs using compositional flow simulation. It is shown that the liquid production from nanoporous rocks is enhanced due to a significant decrease in the bubble point and dew point pressures.
Can We Use Some Methods To Design Surfactants With Ultralow Oil/Water Interfacial Tension?
Authors: Zhu Youyi , Hou Qingfeng , Wang Zhe , Jian Guoqing , Zhang Qun 
Published: June 2014

Abstract
With recent advances in chemical combination flooding, the demand for high performance EOR surfactants is rapidly increasing. One of key parameters of the surfactants used in chemical combination flooding is the ability to decrease interfacial tension (IFT) between crude oil and displacing fluid to ultra-low level (10−3 mN/m). Most of time we use try and error method to screen surfactants, and now we begin to use molecule design theories to select reasonable surfactant molecular structure. Molecule design theories of surfactants, including Hydrophilic-Lipophilic Balance (HLB) value of surfactant, R-ratio (ratio of interaction energy of surfactant and oil with surfactant and water in interface layer), Molecule Geometry Packing Parameter (MGPP) and Quantitative Structure-Property Relationship (QSPR) were introduced and their application for oil displacement surfactants was discussed.
HLB value equal around 6-9 can be used for primary designing and screening of oil-displacement surfactants, which is very convenient. By using HLB empirical equation, the hydrophobic group carbon chain of some of surfactants such as alkylbenzene sulfonate and alkyl naphthalene sulfonate can be optimized. R-ratio, MGPP, QSPR methods can be used in fine designing of oil-displacement surfactants. These methods consider more details of molecule interactions among surfactant, oil and water at interface layer. R-ratio method is still limited by the fact that some interaction energies cannot be measured experimentally. The packing parameter P of MGPP methods can be calculated base on Gibbs adsorption equation with model oil and water. The coincident ratio of MGPP methods for designing oil-displacement surfactants with ultra-low oil/water IFT is high based on 20 surfactants or surfactant mixtures. The correlation model between IFT and molecule structure parameters was established and the coincident ratio of QSPR methods for designing of oil-displacement surfactants with ultra-low IFT of hexadecane/water is good based on 39 surfactants.
Based on molecule design theories, the structure characteristic of surfactants for chemical combination flooding should mainly focus on branch chains, double trails alkyl and/or aryl sulfonate surfactants, zwitterion surfactants, branching chain nonionic-anionic surfactants, gemini surfactants and so on.
Sealing Quality Of Cementing Systems To Be Used on Carbon Capture & Storage CCS Wells
Authors: Tiemeyer C. , Echt T. , Lesti M. , Plank J. 
Published: June 2014

Abstract
Carbon capture and storage (CCS) is considered to be one of the most effective ways to dispose of CO2 generated in coal or gas fired power plants. Cementing such CCS wells presents a technical challenge since ordinary Portland cement (OPC) is known for its corrosion potential with CO2. Such corrosion involves formation and crystallization of CaCO3 from Ca(OH)2 which is formed during the hydration of cement. Furthermore, CaCO3 can be leached as Ca(HCO3)2. This process can create channels in the cementitious matrix for CO2 migration to the surface.
Here, three Portland cement based systems were formulated with different mineral and chemical admixtures and compared with a common API Class G oil well cement with respect to CO2 stability. The systems investigated were based on various concepts. For one cementing system, the aim was to fill the pore space in the cementitious matrix with inorganic, CO2 inert particles while the second was treated with a number of chemical admixtures, particularly latex polymer, to achieve the same goal. The third system was based on slag cement (CEM III) formulated with fly ash.
Hardened specimens (30×50 mm) of the four cementing systems were prepared and stored under supercritical CO2 at 90 °C and 400 bar for one and six months, respectively. The autoclave was half filled with a synthetic reservoir fluid, thus allowing storage in a CO2 saturated salt brine and in wet supercritical CO2 atmosphere. Ingress of CO2 into the hardened cement specimens was probed via phenolphthalein test.
From all systems, only the slag cement (CEM III) blended with a reactive filler (fly ash) exhibited good CO2 resistance. This cement contains a specific ratio of SiO2:CaO which produces only a minor amount of portlandite which can carbonate. For the other cement samples, severe corrosion was observed. The cement system containing chemical admixtures and the neat API Class G system even exhibited severe cracking as a result of high crystallization pressure during CaCO3 growth. Still, carbonation rates were relatively low (~ 0.5 m/year).
The major finding of this study is that common API oil well cement sufficiently withholds CO2 attack if formulated in such way that only minor amounts of CaCO3 are formed, and if the w/c ratio is high enough to provide sufficient pore space for expansion of CaCO3 crystals.
Shale Inhibition: What Works?
Authors: Gomez Sandra , Patel Arvind 
Published: June 2014

Abstract
Understanding the behavior and responses of shale to shale inhibitor additives of drilling and completion fluids has been a challenge for many years because of the numerous and complex chemical and physical variations present in these type of formations. This paper presents the results of laboratory experiments that show how the integration of the geological aspects can help to understand the different responses of the shale to fluids and improve the selection of chemical additives for clay inhibition.
Many of the chemical inhibitor additives have been developed in the laboratory through systematic methods with the use of "standard clay-rich rock samples". These rock samples have relatively simple geologic characteristics and predictable behaviors. The responses of these types of rock samples tend to be consistent and appropriate for evaluations where chemistry of the additives is manipulated constantly. However, the application of these additives goes beyond this approach. In the field, applications target formations that can vary significantly in composition and structure, and simplicity is an uncommon condition. Therefore the challenge for clay stabilization is to integrate many more aspects that can influence the response of the shale formation to fluids.
The paper will present the preliminary process of analysis and understanding of the geologic characteristics of the rock samples and the importance of this fundamental step to achieve the chemical clay stabilization objectives. The paper will include various cases of the inhibitor selection process for shale samples with different characteristics. Chemistry and geology perspectives will be used to analyze the results of the experiments including cases with typical and atypical responses of shale samples. This approach is used to provide a more comprehensive and meaningful interpretation of the rock structural failures due to rock/fluid chemical interactions and, in the same manner, explain how chemical solutions can be used to minimize and control rock instability.