bluuebunny/crossref_metadata_2025_split huggingface dataset:
Solubility Characterization of Asphaltene Deposits
Authors: Rogel E. , Ovalles C. , Moir M. , Vien J. , Morazan H. 
Published: April 2015

Abstract
In view of the great impact of asphaltene deposition in the petroleum industry, it is of paramount importance to estimate the tendency of crude oils and petroleum products towards precipitation as well as the potential amount of material that can precipitate. These are important parameters to consider in designing and monitoring of different processes in the petroleum value chain. It is common knowledge that asphaltene precipitation is strongly related to the colloidal nature of petroleum materials. Rather recently, a new method to evaluate the colloidal stability of crude oils was developed based on the determination of the solubility distribution of asphaltenes. It was found that samples from different origins give different solubility distribution patterns and that those patterns can be correlated to precipitation tendencies of crude oils.
In this work, asphaltene distributions in solid deposits are analyzed and compared to the original asphaltene distributions in the corresponding original oils. Additional chemical and physical properties were also examined and compared. This study aims to link specific asphaltene solubility distribution patterns to the formation of deposits and to find out how asphaltenes found in deposits are compared with the asphaltenes in the materials that originated them. This information is relevant for thermodynamic as well as kinetic modeling of the asphaltene deposition phenomena.
The results indicated significant differences between asphaltenes from the original crude oils and their corresponding deposits. Quantification of these differences in terms of solubility was carried out and showed that asphaltenes from deposits are in average composed of less soluble asphaltenes than those present in the original crude oils. In practical terms, this means that asphaltenes separated using heptane or pentane might not be representative of the asphaltenes found in deposits. The compositional variation of solid deposits seems to point out towards a complex mechanism of formation that is usually not considered in the tools used to model this phenomenon.
A Field Case Study of Inter-well Chemical Tracer Test
Authors: Sanni Modiu L. , Al-Abbad Mohammed A. , Kokal Sunil L. , Hartvig Sven , Olaf Huseby , Jevanord Kjersti 
Published: April 2015

Abstract
Tracers are increasingly being used as effective reservoir monitoring and surveillance (M&S) tool in the oil and gas industry. They can qualitatively or quantitatively gauge how fluid flows through the reservoir. Tracer surveys, conducted either as interwell tests or single-well tests, are one of the enabling technologies that can be deployed to investigate reservoir flow performance, reservoir connectivity, residual oil saturation and reservoir properties that control displacement processes, particularly in improved oil recovery (IOR) and enhanced oil recovery (EOR) operations.
An inter-well chemical tracer test (IWCTT) was designed and implemented in a carbonate field with a diffuse fracture network on peripheral water-flood to determine reservoir connectivity, water breakthrough times, and fluid saturations. The reservoir is heterogeneous with layers of high to low permeability limestone with porosity a range of 20-30%, and interspersed with patchy layers of dolomites and a very competent anhydrite seal. The IWCTT was conducted on a very mature part of the field near the peripheral water injectors to determine the effectiveness of infill injector wells. Four distinct tracers were injected into four individual injectors and the residuals were monitored in four “paired” producers.
This paper reviews the complete design and implementation of the test, operational issues, and the analyses and interpretation of the results. The breakthrough times of the tracers are reported and interwell connectivity between the paired and cross-paired injectors and producers are analyzed. Tracers were detected in three of the paired producers, albeit at different breakthrough times. One tracer was also detected in a cross-paired producer. The tracer results were modeled using the current reservoir simulation model with fairly good matches. The tracer data were then used to fine tune the current reservoir simulation model. The IWCTT has been very effective in analyzing well interconnectivity in the reservoir and has led to better reservoir description and an improved dynamic simulation model. Plans for further implementation of this important M&S tool will also be shared.
Development and Qualification of New Zinc and Lead Sulphide Scale Inhibitors for Application under Harsh Conditions
Authors: Baraka-Lokmane S. , Hurtevent C. , Tillement O. , Simpson C. , Graham G.M. 
Published: April 2015

Abstract
The paper will describe the challenges facing sulphide scale control in the challenging environment found in Totals Elgin and Franklin Fields. It will present the advances made in developing new thermally stable and compatible chemical inhibitors able to withstand the extreme conditions in these fields. The paper will then describe the test methodologies and experimental approach developed to examine the performance of various prototypes or candidate chemicals followed by more detailed testing on selected chemicals under the more challenging field representative conditions as well as application specific testing for both squeeze treatment and downhole continuous injection at temperatures of 196°C/282 °F.
In collaboration with University of Lyon Total has developed a range of new inhibitor types specifically designed to inhibit sulphide scales and remain stable under the harsh conditions of these fields. The chemicals have been qualified independently using recently developed test methodologies for lead and zinc sulphide and show better performance against these unconventional scales comparing to the other chemistries examined. In addition, a new method was developed for scale inhibitor residual analysis. This method based on time resolved fluoroscopy allows a quick and very sensitive measurement.
The work concludes that a new range of Zn/Pb sulphide specific chemicals have been developed for field application with selected species also being suitable for application under the extreme conditions of the Elgin and Franklin Fields.
Zinc and lead sulphide scales became an increasing challenge in oil and gas production. More specifically when formed from wells producing under very severe conditions of high temperature (196°C/282 °F) and high salinity formation waters such as those experienced in Central Graben Fields, their prevention by conventional scale inhibitors has proved challenging. To date after extensive chemical qualification over several years, no conventional scale inhibitor has been found which can both inhibit lead and zinc sulphide and survive under the extreme conditions of these fields. Therefore, the results in this paper represent a significant advance in the ability to control sulphide scales and test the inhibition under appropriate conditions.
Efficient Si Removal from Recycled Water for Steam Injection Using Unique Electrocoagulation Process
Authors: Cao Jiasheng , Monroe Steve 
Published: April 2015

Abstract
In many areas water used for steam flood injection has varied concentrations of dissolved silicon (Si), which can form silica scale, reducing thermal efficiency, and lowering steam quality. Scale inhibitors are typically used today, but removal of Si may be a more cost-efficient process to reuse the water, especially in areas with limited fresh water availability. Removing Si in the water treatment plant before steam generation can lead to higher quality steam at lower costs and result in better production.
Typical chemical precipitation methods have been reported for Si removal by adding different coagulant compounds that contain elements such as aluminum (Al), iron (Fe) or molybdenum (Mo). In general, the chemical precipitation method needs high volumes of coagulants and generates considerable amounts of sludge, and may also input extra compounds or ions into the treated water. Electrocoagulation (EC) has been claimed for Si removal, but low conductivity water (or low concentration of total dissolved salt (TDS)), as seen in steam injection systems, is not well-matched to traditional EC systems.
In this paper, a uniquely designed electrocoagulation (EC) system with non-sacrificial electrodes and sacrificial material was tested for Si removal from steam injection water. This EC system has been shown to be highly flexible and efficient for treating waters with TDS levels from 3,000 to over 300,000 mg/L, especially for Si, Fe, and suspended solid removal. The water in this case was hot (180°F), low TDS (&lt;6,000mg/L), and had 60 to 80 mg/L of Si. Both laboratory scale testing and pilot field trial showed efficient Si removal from the water to less than 2 mg/L at varied temperatures. Significant hardness removal was also achieved during the same process. Compared with chemical precipitation methods, this unique EC system used fewer chemicals, generated less sludge, and provided a higher quality of effluent water.
Interaction between Scale Inhibitors and Shale and Sandstone Formations
Authors: Yan Fei , Zhang Fangfu , Bhandari Narayan , Liu Ya , Wang Lu , Dai Zhaoyi , Zhang Zhang , Bolanos Valerie , Kan Amy , Tomson Mason 
Published: April 2015

Abstract
The reactions between scale inhibitors and formation minerals determine the inhibitor retention and release after inhibitor squeeze treatment and hydraulic fracturing. Scale inhibitor is an important ingredient in fracturing fluids to prevent mineral scale depositions during fracturing, shut-in and flowback stages. The interaction of scale inhibitors between carbonate formation is well understood but the interaction of scale inhibitors between shale and sandstone formation has not been investigated thoroughly. The primary objective of this study is to develop mechanistic understanding of interactions between scale inhibitors and shale and sandstone minerals.
In this study, adsorption and precipitation of a phosphonate scale inhibitor – DTPMP on shale minerals were investigated at 70°C. Equilibrium adsorption isotherms were determined for various inhibitor concentrations at different pH values. At low phosphonate concentration, the interaction between inhibitors and shale can be characterized as surface adsorption; at high phosphonate concentrations, inhibitors precipitate with cations released from shale minerals. The interaction of scale inhibitor and sandstone formation was evaluated in coreflooding experiments by repeated squeeze and acid treatment. The inhibitor return of an identical second DTPMP squeeze showed almost the same return curve as the first squeeze. An acidizing pretreatment demonstrated improvements in squeeze performance. It is proposed that acid treatment dissolves soluble minerals such as calcite, and DTPMP inhibitors forms less soluble precipitate such as iron phosphonate in the formation, which results in the enhancement of squeeze. The dissolution rate constant of DTPMP precipitate was determined at three different temperatures and the established relationship can be used to predict rate constant under other temperature conditions.
The insights presented in this work will help to understand the fate of phosphonate scale inhibitor in shale and sandstone reservoirs, manage the use of scale inhibitor in fracturing fluids, and design optimum scale squeeze packages for scale control in oil field.
Ferrous Iron Impact on Phosphonate and Polymeric Scale Inhibitors at Temperature Ranging from 25 to 70°C
Authors: Zhang Zhang , Zhang Fangfu , Wang Qiliang ‘Luke’ , Bhandari Narayan , Yan Fei , Liu Ya , Dai Zhaoyi , Wang Lu , Bolanos Valerie , Kan Amy T. , Tomson Mason B. 
Published: April 2015

Abstract
Ferrous iron (Fe2+) is one of the most common cations existing in oil and gas production water. Most Fe2+ ions come from dissolution of siderite in reservoir and corrosion of steel pipes. Compared to Ca2+ and Mg2+, Fe2+ has a higher complex stability constant with some common inhibitor function groups like phosphonate and carboxyl due to its transition metal structure. Therefore, understanding the influence of Fe2+ on inhibitors is important to enhance inhibition performance. Work still remain to be done to understand the effect of Fe2+ on scale inhibition, including a systematic study of the Fe2+ influence on phosphonate and polymeric scale inhibitors at different pH, values and molar ratios. Little research has been done at temperatures above room temperature, probably due to the difficulty of developing strictly anoxic test apparatus. In this study, a new anoxic laser apparatus is designed to test inhibitor performance. This newly designed apparatus features constant Argon gas headspace purging during an experiment to guarantee a strict maintenance of anoxic condition. This anoxic apparatus is based on laser detection method of nucleation induction time. It is easy to operate and enables experiments to be conducted at temperatures up to 200°F.
High Temperature, High Performance Water-Based Drilling Fluid for Extreme High Temperature Wells
Authors: Galindo Kay A. , Zha Weibin , Zhou Hui , Deville Jay P. 
Published: April 2015

Abstract
High performance (HP) water-based drilling fluids are particularly advantageous compared to conventional water-based systems because they provide faster penetration rates, enhanced hole cleaning, greater shale inhibition, and improved wellbore stability. Most high performance water-based drilling fluids only tolerate operating temperatures up to 300°F because they depend on biopolymer-based viscosifiers. Deeper exploration in extreme high temperature reservoirs (&gt;300°F) requires new drilling fluid technologies. A new high performance, high temperature water-based drilling fluid that is both thermally and rheologically stable at 400°F was developed to meet these demands.
A novel synthetic polymer was developed for use in a new HP water-based mud (WBM). The new fluid system was hot rolled at 150°F for 16 hours to condition the fluid before testing. The conditioned fluids were subjected to dynamic or static aging conditions, with temperatures ranging from 300 to 400°F. The viscosity and pH values were determined with a direct indicating viscometer and pH meter, respectively. The Anton Paar viscosity was measured using the CC. 27 cup and bob geometry. The fluid loss properties of the fluids were determined by high pressure/high temperature (HP/HT) filtration at 350°F according to the API recommended practice.
This paper provides an overview of the current high performance drilling fluid chemistry, as well as the detailed study of the high temperature, high performance water-based drilling fluid formulated with 10.0 to 17.0 lbm/gal densities that exhibits a stable rheological profile. For example, a 14.0 lbm/gal formulation aged at 150°F for 16 hours provided a plastic viscosity (PV) of 29 cp and a yield point (YP) of 22 lbf/100 ft2. After static aging for 48 hours at 400°F, the fluid provided a PV of 27 cp and YP of 24 lbf/100 ft2. The new fluid maintains viscosity, adequate suspension, low shear strengths, shale stability, and filtration control up to 400°F, and the fluid is resistant to contamination.
This clay-free system uses a novel synthetic polymer viscosifier and filtration control agent, enabling the removal of thermally labile biopolymers without the addition of clay-based viscosifiers; it is environmentally acceptable for both land and offshore drilling and can be formulated with either chloride containing or non-chloride containing salts. The new fluid formulation provides reliable thermal stability that can function in extreme high temperature wells, while preserving the benefits of HP water-based drilling fluids.
Recent Advances in Viscoelastic Surfactants for Improved Production from Hydrocarbon Reservoirs
Authors: Hull Katherine L. , Sayed Mohammed , Al-Muntasheri Ghaithan A. 
Published: April 2015

Abstract
Viscoelastic surfactants (VES) are used in upstream oil and gas applications, particularly hydraulic fracturing and matrix acidizing. A description of surfactant types is introduced along with a theoretical description of how they assemble into micelles, what sizes and shapes of micelles can be formed under different conditions, and finally how specific structures can lead to bulk viscoelastic solution properties. This theoretical discussion leads into a description of the specific VES systems that have been used over the last twenty years or so in improved oil recovery for upstream applications.
VES-based fluids have been used most extensively for hydraulic fracturing. They are preferred over conventional polymer-based fracturing fluid systems because they are essentially solids-free systems which have demonstrated less damage to the reservoir rock formation. Important advancements in VES have been made by introducing “pseudo-crosslinking agents” such as nanoparticles to enhance the viscosity. Fracturing fluid systems based on VES have also been improved recently by developing internal breakers to lower their viscosity in order to flow back the well. The flexibility of VES-based fluids has been demonstrated by their application as foamed fluids as well as their incorporation with brine systems such as produced water.
A second key area that has benefited from VES-based systems is matrix acidizing carbonated-based reservoirs. The viscosity of these VES-based fluids is mostly controlled by pH where, at low pH (low viscosity), the acid system flows easily and invades pore spaces in the formation. During acidizing, the acid is spent, and the pH and viscosity increase. Because the spent acid has higher viscosity, fresh acid is diverted to low permeability un-contacted zones and penetrates the rocks to form wormholes. A number of experimental studies and field applications to these effects have been performed and will be described here.
In order for VES-based fluids to play a more prominent role in the field, inherent limitations such as cost, applicable temperature range, and leak-off characteristics will need to continue to be addressed. If we can efficiently and economically overcome these issues, VES-based fluids offer the industry an excellent clean, non-damaging alternative to conventional polymer-based fluids.
A Highly Effective Corrosion Inhibitor Based on Gemini Imidazoline
Authors: Yang Jiang , Liu Xuan , Jia Shuai , Qin Wenlong , Yin Chengxian , Liu Chen 
Published: April 2015

Abstract
Corrosion inhibitors are widely used to control corrosion under the sweet and sour environments in oil and gas industries. More effective and environment friendly corrosion inhibitors need to be developed. This paper studies a new gemini imidazoline corrosion inhibitor, which two hydrocarbon chains and two headgroups are linked by a rigid spacer. The gemini imidazoline was synthesized through the reaction of oleic acid with triethylene tetramine at 2:1 molar ratio. The product was characterized by infrared spectroscopy, chromatography and mass spectroscopy. The performance of the gemini imidazoline on inhibition of CO2 corrosion was evaluated by linear polarization resistance in sparged beaker testing. Rotating wheel testing was performed to evaluate the film persistency of the test inhibitors. The results showed that corrosion inhibition of the gemini imidazoline was more effective at lower concentration than that of conventional imidazoline. The gemini imidazoline mixed with fatty acid also showed better film persistency than that of conventional imidazoline. The emulsion tendency of the gemini imidazoline was less than that of conventional imidazoline. The mechanism of the highly effective gemini imidazoline was studied. It showed that gemini imidazoline has much higher surface activity than that of conventional imidazoline. The critical micelle concentration is several times lower than that of conventional imidazoline. Hence, the new gemini imidazoline (GIM) corrosion inhibitor and its mixture give more effective corrosion inhibition at low concentration, which also has less environmental impact.
Development Of A Very Low Peroxide Containing Peracid Formulation As Superior Treatment Option For Water Reuse Applications
Authors: Balasubramanian Ramakrishnan , Ryther Robert , De Paula Renato , Epps Brian , Keasler Victor , Li Junzhong , Staub Richard 
Published: April 2015

Abstract
The shale gas and oil wells drilled and completed in the United States in 2013 alone consumed about 1.8 billion gallons of water. With the increase in gas exploration, through natural and unconventional production, this consumption rate and need for water will increase dramatically. A recent study estimates about 3-6 million gallons of water per frac with volumes as high as 10 million reported for some areas. This increasing demand for water necessitates its reuse and development of critical technologies that aide in water treatment and reuse.
In the last few years, peracetic acid treatment has distinguished itself as a safe water treatment as well as a superior, cost effective biocide for water treatment applications. In addition, peracetic acid break down into environmentally safe components providing a low-risk option for routine water treatment in the oil and gas industry. One of the potential issues with the use of conventional peracetic acid is the presence of peroxide in the formulation that increases chances of incompatibility with cross-linked gel, friction reducers and scale inhibitors.
Nalco Champion’s new formulation, EC6779A, is an EPA registered biocide that increases the ratio of peracetic acid to peroxide. This new formulation allows for a rapid microbial kill in addition to its increased compatibility with most cross-linked gel packages while maintaining all the advantages of a traditional peracetic acid formulation. This reduced peroxide formulation also increases the stability of the peracetic acid, does not require an onsite generation, and kills bacteria usually associated with microbial induced corrosion (SRB, APB and GHBs), in addition to greatly reducing oxygen induced corrosion in oilfield systems. The new formulation is also dispensable using existing peracid systems and has proved to be a very safe and cost competitive alternative to chlorine dioxide.